As filed with the Securities and Exchange Commission on April 10, 2017.March 9, 2021.

Registration No. 333-            333-253366

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 3

to

FormS-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

VINE RESOURCESENERGY INC.

(Exact name of registrant as specified in its charter)

5800 Granite Parkway, Suite 550

Plano, Texas 75024

(469)606-0540

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Eric D. Marsh

Chairman and Chief Executive Officer

5800 Granite Parkway, Suite 550

Plano, Texas 75024

(469)606-0540

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Approximate date of commencement of proposed sale of the securities to the public:

As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box:  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company” and “emerging growth company” in Rule12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☒☐

CALCULATION OF REGISTRATION FEE

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. ThisThe prospectus is not an offer to sell these securities and it is not solicitingnor a solicitation of an offer to buy these securities in any state or jurisdiction where the offer orand sale is not permitted.

Subject to Completion, dated April 10, 2017March 9, 2021

PROSPECTUS

18,750,000 Shares

Vine ResourcesEnergy Inc.

Class A Common Stock

This is the initial public offering of the common stock of Vine ResourcesEnergy Inc., a Delaware corporation. We are offering 18,750,000 shares of our Class A common stock. No public market currently exists for our Class A common stock.

We have appliedintend to list our Class A common stock on the New York Stock Exchange under the symbol “VRI.“VEI.”

We anticipate that the initial public offering price will be between $$16.00 and $$19.00 per share.

Holders of shares of our Class A common stock and Class B common stock are entitled to one vote for each share of Class A common stock and Class B common stock, respectively, held of record on all matters on which stockholders are entitled to vote generally. See “Description of Capital Stock.”

After the completion of this offering, affiliates of The Blackstone Group L.P. will beneficially own approximately 73.0% of the combined voting power of our Class A and Class B common stock. As a result, we will be a “controlled company” within the meaning of the New York Stock Exchange rules. See “Management—Status as a Controlled Company.”

Investing in our Class A common stock involves risks, including those described under “Risk Factors” beginning on page 2130 of this prospectus.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012, and as such, we have elected to take advantage of certain reduced public company reporting requirements for this prospectus and future filings. “Risk Factors” and “Prospectus Summary — Summary—Emerging Growth Company Status” contain additional information about our status as an emerging growth company.

We have granted the underwriters the option to purchase up to 2,812,500 additional shares of Class A common stock on the same terms and conditions set forth above if the underwriters sell more than 18,750,000 shares of Class A common stock in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares on or about                 , 2017.2021.

Joint Book-Running Managers

Prospectus dated                 , 20172021

Cutaway view showing co-development of the Haynesville and overlying Mid-Bossier. Multiple wells are drilled from each surface location to increase drilling efficiency and the laterals are spaced to optimize recovery.

TABLE OF CONTENTS

You should rely only on the information contained in this prospectus and any free writing prospectus prepared by us or on behalf of us or to the information which we have referred you. Neither we nor the underwriters have authorized anyone to provide you with information different from that contained in this prospectus and any free writing prospectus. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the underwriters are offering to sell shares of Class A common stock and seeking offers to buy shares of Class A common stock only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Class A common stock. Our business, financial condition, results of operations and prospects may have changed since that date. We will update this prospectus as required by law, including with respect to any material change affecting us or our business prior to the completion of this offering.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements” contain additional information regarding these risks.

Through and including                 , 2021 (the 25th day after the date of this prospectus), all dealers effecting transactions in our shares, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

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Commonly Used Defined Terms

As used in this prospectus, unless the context indicates or otherwise requires, the terms listed below have the following meanings:

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Glossary of Oil and Natural Gas Terms

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

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In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of our predecessor as of the dates and for the periods presented. Unless another date is specified or the context otherwise requires, all acreage, well count, hedging and drilling location data presented in this prospectus is as of December 31, 2016. Unless otherwise noted, references to production volumes refer to sales volumes reflective of our net interest.

Certain amounts and percentages included in this prospectus have been rounded. Accordingly, in certain instances, the sum of the numbers in a column of a table may not exactly equal the total figure for that column.

Presentation of Financial and Operating Data

Unless otherwise indicated, the summary historical consolidated financial information presented in this prospectus is that of our predecessor. Additionalaccounting predecessor, Vine Oil & Gas. The pro forma financial information may be found underpresented in this prospectus treats the combination of Vine Oil & Gas, Brix and Harvest in connection with our corporate reorganization as an acquisition in a business combination of Brix and Harvest by Vine Oil & Gas. Please see “Corporate Reorganization” and the unaudited pro forma financial statements“Unaudited Pro Forma Condensed Combined Financial Statements” included elsewhere in this prospectus.

In addition, unless otherwise indicated, the reserve and operational data presented in this prospectus is that of Vine Oil & Gas, Brix and Harvest on a combined basis as of the dates and for the periods presented.

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Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications and other published independent sources. Although we believe these third-party sources are reliable as of their respective dates, neither we nor the underwriters have independently verified the accuracy or completeness of this information. These sources include an article entitled Study Forecasts Gradual Haynesville Production Recovery Before Final Decline, dated December 2015, by The Oil & Gas Journal, reports entitled Haynesville Inventory, dated April 2020, and Enverus Gas Plays and Market Outlook, dated October 2020, by Enverus, reports entitled World Energy Outlook 2020, dated October 2020, and Global EV Outlook 2020, dated June 2020, by IEA (as defined below), reports entitled Annual Energy Outlook 2020, dated January 2020, and U.S. Energy-Related Carbon Dioxide Emissions, 2019, dated September 2019, by EIA (as defined below), presentations entitled North America Gas Market Outlook, dated July 2020 and North America Energy Markets, dated November 2020, by Wood Mackenzie, and Rig Count by Baker Hughes, dated November 2020. The industry in which we operate is subject to a high degree of uncertainty and risk due to a variety of factors, including those described in the section entitled “Risk Factors.” These and other factors could cause results to differ materially from those expressed in these publications.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ®,^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the rights of the applicable licensor to these trademarks, service marks and trade names.

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RISK FACTORS

Investing in our Class A common stock involves risks. The information in this prospectus should be considered carefully, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The risks and uncertainties described below are not the only ones we face. Additional risks not presently known to us or that we currently deem immaterial may also materially affect our business. The occurrence of any of the following risks or additional risks and uncertainties that are currently immaterial or unknown could materially and adversely affect our business, financial condition, liquidity, results of operations, cash flows or prospects. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment.

Risks Related to Our Business

Natural gas prices are volatile. A reduction or sustained decline in prices may adversely affect our business, financial condition or results of operations and our ability to meet our financial commitments.

Prevailing natural gas prices heavily influence our revenue, profitability, access to capital, growth rate and value of our properties. Further, although we do not produce oil, to the extent oil prices rise considerably, the cost of services we incur may also increase. As a commodity, gas prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the natural gas market has been volatile. Prices for domestic natural gas began to decline during the third quarter of 2014 and have been pressured since then, despite a modest recovery in oil prices. Spot prices for Henry Hub generally ranged from $2.00 per MMBtu to $4.00 per MMBtu over the period from 2014 to 2017.pressured. Our revenue, profitability and future growth are highly dependent on the prices we receive for our natural gas production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

If commodity prices decrease or we experience negativewidening of basis differentials, our cash flows and refinancing ability will be reduced. We may be unable to obtain needed capital or financing on satisfactory terms,

which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas that we can produce economically. Additionally, a significant portion of our projects could become uneconomic and require us to abandon or postpone our planned drilling, which could result in downward adjustments to our estimated proved reserves. As a result, a reduction or sustained decline in natural gas prices may materially and adversely affect our financial condition, results of operations, liquidity and our ability to finance CapEx.

Our business and operations have been adversely affected by, and are expected to continue to be adversely affected by, the COVID-19 pandemic, and may be adversely affected by other similar outbreaks.

As a result of the COVID-19 pandemic or other adverse public health developments, including voluntary and mandatory quarantines, travel restrictions, and other restrictions, our operations, and those of our subcontractors and customers, have and are anticipated to continue to experience delays or disruptions and temporary suspensions of operations. In addition, our financial condition and results of operations have been and are likely to continue to be adversely affected by the COVID-19 pandemic.

The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.

The timeline and potential magnitude of the COVID-19 outbreak are currently unknown. The continuation or amplification of this virus could continue to more broadly affect the United States and global economy, including our business and operations, and the demand for oil and gas. For example, the outbreak of coronavirus has resulted in a widespread health crisis that will adversely affect the economies and financial markets of many countries, resulting in an economic downturn that may affect our operating results. Other contagious diseases in the human population could have similar adverse effects. In addition, the effects of COVID-19 and concerns regarding its global spread have negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility. As the potential impact from COVID-19 is difficult to predict, the extent to which it will negatively affect our operating results, or the duration of any potential business disruption is uncertain. The magnitude and duration of any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which are beyond our control.

We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our production and natural gas reserves.

Our industry is capital intensive, requiring substantial CapEx to develop and acquire natural gas reserves. The actual amount and timing of our future CapEx may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction or sustained decline in natural gas prices from current levels may force us to reduce our CapEx, which would negatively impact our ability to grow production. We intend to finance our CapEx through cash flow from operations and through available capacity under our New RBL; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness requires compliance with the terms of our existing indebtedness and would require us to incur additional interest and principal, which may affect our ability to fund working capital, CapEx and acquisitions.

Our cash flow from operations and access to capital are subject to a number of variables,many factors, including:

If our cash flow decreases as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to fund our planned CapEx or operations. If additional capital is needed, we may not be able to obtain financing on terms acceptable to us, if at all.

Our business strategy includes continued use of advancements in horizontal drilling and completionD&C techniques, which involve risks and uncertainties in their application.

Our current and future operations involve utilizing some of the latest drilling and completionD&C techniques. While drilling and completingdeveloping our wells, we face risks associated with:

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to property, reserves and equipment, pollution, environmental contamination and regulatory penalties.

Our gathering contracts require fees on minimum volumes regardlessoperations are concentrated in the Haynesville Basin of throughput.Northwest Louisiana, making us vulnerable to risks associated with operating in a limited geographic area.

Our gathering contracts require deliveryAll of minimum volumes of gas for each annual contract period and require settlement payments for any shortfallsour producing properties are geographically concentrated in the gathered volumes. The minimum volume commitmentsnorth western Haynesville Basin. As a result, we may be disproportionately exposed to various factors, including, among others: (i) the impact of regional supply and demand factors, (ii) delays or interruptions of production from wells in such areas caused by governmental regulation, (iii) processing or transportation capacity constraints, (iv) market limitations, (v) availability of equipment and personnel, (vi) water shortages or other drought related conditions or (vii) interruption of the processing or transportation natural gas. This concentration in a limited geographic area also increases our gathering contracts step down from 705,000 MMbtudexposure to changes in 2016local laws and regulations, certain lease stipulations designed to 377,000 MMbtudprotect wildlife and unexpected events that may occur in August 2019the regions such as natural disasters, seismic events, industrial accidents or labor difficulties. Any one of these factors has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and to 95,000 MMbtud in April 2020capital costs and prevent development of lease inventory before expiring in January 2021. Asexpirations. Any of December 31, 2016, our expected annual future cash obligation under these agreements is$75-80 million. The fees we are required to pay under these gathering contracts maythe risks described above could have a material adverse effect on our liquidity andbusiness, financial condition, results of operations.operations and cash flow.

Our revenue will ultimately depend on our ability to transport our gas to various sales points.

We do not own or control third-party transportation facilities (i.e. gas transport pipelines) and our access to them may be limited or denied, because we do not have contracts for firm transportation. We currently sell our gas at the tailgate of our gatherer’s treating plants. The purchasers of our gas are typically parties who hold firm transportation and who, after taking possession of our gas, use it to fulfill their volume commitments. Today, there is ample transportation capacity, and there are ample holders of firm transportation who are willing to engage in the types of arrangements we use. If demand for transportation surged or if parties holding firm transport satisfied volume commitments with their own or others’ gas, we may be unable to sell our gas, which would materially and adversely affect our financial condition and results of operations.

We may be unable to generate sufficient cash to service all of our indebtedness and financial commitments.

Our ability to make scheduled payments on or to refinance our indebtedness and financial commitments depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certainincluding financial, business and other factors beyond our control. We may be unable to generate sufficient cash flow to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt and other obligations, we may be forced to reduce or delay CapEx, sell assets, seek additional capital or restructure our indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to service our debt would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. If we face substantial liquidity problems, we might be required to sell assets to meet debt and other obligations. Our debt restricts our ability to dispose of assets and dictates our use of the proceeds from such disposition. We may not be able to consummate dispositions, and the proceeds of any such disposition may be inadequate to meet obligations.

We may be unable to access adequate funding as a result of a decrease in borrowing base due to an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover a defaulting lender’s portion. As a result, we may be unable to execute our development plan, make acquisitions or otherwise conduct operations, which would have a material adverse effect on our financial condition and results of operations.

Restrictions associated with our debt agreements could limit our growth and our ability to engage in certain activities.

Our debt agreements contain a number of significant covenants that may limit our ability to, among other things:

indebtedness which would have a material adverse effect on us. If an acceleration occurs, it would likely accelerate all of our indebtedness through cross-default provisions and we would likely be unable to make all of the required payments to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.

Reserve estimates depend on many assumptions that may turn out to be inaccurate.

The process of estimating natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we project production rates, timing and pace of development. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as D&C costs, operating costs, and production and ad valorem taxes.

Actual future production revenue, taxes, development costs and operating expenses will vary from our estimates. In addition, we may adjust reserve estimates to reflect production history, changes in existing commodity prices and other factors, many of which are beyond our control.

We do not believe that the present value of future net revenue from our reserves calculated in accordance with the method prescribed by the SEC is the current market value of our reserves. We generally base the estimated value of our properties on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in current estimates.

We will not be the operator on a substantial portion of our existing and future producing locations.

Of our future drilling locations, we do not expect to operate approximately half of such locations almost all of which we expect GEP to operate. Our JOA with GEP provides for our ability to propose wells on acreage operated by them; however, we still have lesser rights than we would have if we were the operator, and there is risk that our partners may have economic, business or legal interests or goals that are inconsistent with ours.

Furthermore, the development activities conducted by GEP will depend on a number of factors that will be largely outside of our control, including:

These factors, to the extent not aligned with our objectives, could adversely impact the expected rate and success of our development.

We participate with third parties who may have economic, business or legal interests or goals that are inconsistent with ours.

We own less than 100% of the working interest in the areas where we conduct operations, and other parties own the remaining portion of the working interest. Our JOA with GEP provides that either we or GEP may propose wells on acreage operated by the other party; however, in the event that either party does not consent to such a proposal, the proposing party is permitted to drill the well at their cost. If we choose not to participate on a well proposed by GEP and they proceed to drill that well, we would be excluded from the costs and economic benefits of that well, likely for its entire life. This could cause a material change in the value of the assets we own and could yield recognition of impairments and forgone rights of ownership. Furthermore, with respect to GEP’s operated properties, we generally have lesser rights than we would have if we were the operator, and there is a risk that our partners may have economic, business or legal interests or goals that are inconsistent with ours.

Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties regarding the timing or likelihood of their development. In addition, we may lack sufficient capital necessary to develop our identified drilling locations.

We have a multi-year development plan. Theseto-be-developed drilling locations represent a significant part of our growth strategy. Our ability to develop these drilling locations depends on a number of uncertainties, including natural gas prices, the availability and cost of capital, drilling and production costs, availability of services and equipment, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, we will require significant capital over a prolonged period in order to develop these drilling locations, and we may not be able to raise, generate or maintain the capital required to do so. Because of these uncertainties, we cannot be certain that all identifieddrilling locations may be developed successfully.

All of our producing properties are located in the Haynesville andMid-Bossier shale in Northwest Louisiana, making us vulnerable to risks associated with operating in only one geographic area.

As a result of our geographic concentration, an adverse development in the industry in our operating area could have a greater impact on our financial condition and results of operations than if we were more geographically diverse. We may also be disproportionately exposed to the impact of regional supply and demand factors, impact of governmental regulation, or midstream capacity constraints. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

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

The existence of a material title deficiency can render a lease worthless. In the course of acquiring the rights to develop natural gas, it is standard procedure for us and the lessor towe typically execute a lease agreement with payment

to the lessor subject to title verification. In mostmany cases, we incur the expense of retaining lawyers to verify the rightful owners of the gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of a natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. 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. Accordingly, 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 will suffer a financial loss.

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

Developed natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. We must conduct ongoing development activities to avoid declines in our proved reserves and production. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, 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 would be adversely affected.

The credit risk of financial institutions could adversely affect us.

We have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative transactions in connection with our hedges and insurance companies in the form of claims under our policies. In addition, ifIf any lender under the RBL or the New RBL is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under the RBL.RBL or the New RBL, respectively.

The failure of our hedge counterparties, significant customers or working interest holders to meet their obligations to us may adversely affect our financial results.

Our hedging transactions expose us to the risk that a counterparty fails to perform under a derivative 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 derivative contract and we may not be able to realize the benefit of the derivative contract. Any default by the counterparty to these derivative contracts when they become due would have a material adverse effect on our financial condition and results of operations.

We also face credit risk through joint interest receivables and the sale of our natural gas production, which totaled approximately 30 purchasers during 2016.production. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. We are also subject to credit risk due to concentration of our natural gas receivables with several significant customers. We do not require our customers to post collateral. The inability or failure of our significant customers or working interest holders to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

We may not be able to enter into commodity derivatives on favorable terms or at all.

We enter into financial commodity derivative contracts to mitigate financial risk caused by changes to market factors. This helps reduce potential negative effects of reductions in gas prices but also reduces our ability to benefit from increases in gas prices. Moreover, our Second Lien Term Loan requires us to have 70% of our total expected production hedged 24 months forward. However, we currently rely on lessfewer than ten counterparties with whom we have negotiated operative hedging documents. We have, at times, been unable to secure sufficient capacity with these counterparties, even when markets reached a level at which we would have been willing to transact. If we are unable to maintain sufficient hedging capacity with our counterparties, we could have greater exposure to changes in commodity prices and LIBOR,interest rates, which could have a material adverse impact on our business, financial condition and results of operations.

Increased attention to environmental, social and governance (“ESG”) matters may impact our business.

Increasing attention to climate change, increasing societal expectations on companies to address climate change, increasing investor and societal expectations regarding voluntary ESG disclosures, and potential

increasing consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our access to capital markets. Increasing attention to climate change, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against the company. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward the company and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, institutional lenders may, of their own accord, elect not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

Our operations are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities that could exceed current expectations.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the release, disposal or discharge of materials into the environment, health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations including the acquisition of a permit before conducting regulated drillingdevelopment activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, habitat of protected species, and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from the ownership or operation of our operations.oil and gas properties. Numerous governmental authorities such as the U.S. Environmental Protection Agency (“EPA”), and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. We may be required to make significant capital and operating expenditures or perform remedial or other corrective actions at our wells and properties to comply with the requirements of these environmental laws and regulations or the terms or conditions of permits issued pursuant to such requirements. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. “Business—Regulation of Environmental and Occupational Safety and Health Matters” contains further description of the laws and regulations that affect us.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be held strictly liable for the removal or remediation of previously released hazardous materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result

from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general in addition to our own results of

operations, competitive position or financial condition. For example, the EPA has designated energy extraction as one of six national enforcement initiatives for 2014 to 2016 and 2017 to 2019, and has indicated that the agency will direct resources towards addressing incidences of noncompliance from natural gas extraction and production activities. Also, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source forair-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. To the extent laws are enacted or other governmental action is taken that restricts drillingdevelopment or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Federal and state legislative and regulatory initiatives regarding hydraulic fracturing and related activities, as well as governmental reviews of such activities, could increase our costs of doing business, result in additional operating restrictions or delays, limit the areas in which we can operate and reduce our natural gas production, which could adversely impact our production and business.

Hydraulic fracturing is an important and common practice that is usedwe use to stimulate production of natural gas and/or oil from dense subsurface rock formations.gas. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, thereThere has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies and increase seismicity, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.

At present, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Along with several other states, Louisiana (where we conduct operations) has adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. At the federal level, the United States Environmental Protection Agency (“EPA”) has conducted investigations that focus on potential impacts of hydraulic fracturing on drinking water resources and asserted federal regulatory authority over various activities associated with hydraulic fracturing by issuing various guidance, notices, rules and regulations.

In addition, hydraulic fracturing operations require the use of a significant amount of water. The inability to locate sufficient amounts of water, or dispose of or recycle water used in drilling and production operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on the ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the development or production of natural gas.

Finally, in some instances, the operation of underground injection wells for the disposal of waste has been alleged to cause earthquakes. In Oklahoma, for example, such issues have led to orders prohibiting continued injection or the suspension of drilling in certain wells identified as possible sources of seismic activity. Such concerns also have resulted in stricter regulatory requirements in some jurisdictions relating to the location and operation of underground injection wells. Although our operations are not located in those jurisdictions, any future orders or regulations addressing concerns about seismic activity from well injection in jurisdictions where we operate could affect our operations.

If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process and disposal activities are adopted in areas where we operate, we could incur potentially significant added costs or permitting requirements to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, EPA has asserted federal regulatory authority pursuant “Business—Regulation of Environmental and Occupational Safety and Health Matters—Hydraulic Fracturing” contains further description of the laws and regulations relating to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. In May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. Further, the EPA finalized regulations under the federal Clean Water Act (“CWA”) in June 2016 prohibiting wastewater discharges from hydraulic fracturing and certain other natural gas operations to publicly-owned wastewater treatment plants. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. In addition, the federal Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands; however, the U.S. District Court of Wyoming struck down this rule in June 2016. An appeal of this decision is pending. On March 15, 2017, the BLM filed a motion in the appeal, requesting the court to hold the case in abeyance pending rescission of the rule.affect us.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.or reduced prices.

Pursuant to thefederal legislative authority under the Natural Gas Pipeline Safety Act (“NGPSA”) and the Hazardous Liquid Pipeline Safety Act (“HLPSA”), as amended by the Pipeline Safety Improvement Act of 2002, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”),governing pipeline safety matters, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines that in the event of a pipeline leak or rupture could affect “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources and unusually sensitive ecological areas. These regulations requiremay impact operators of covered pipelines to:

sales points for our product.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines. At this time, we cannot predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the number and extent of any repairs found topipelines which may be necessary as a result of pipeline integrity testing, but 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 safe and reliable operation of our pipelines.

The 2016 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. The 2016 Pipeline Safety Act extends PHMSA’s statutory mandate through 2019 and, among other things, requires PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and to develop new safety standards for natural gas storage facilities by June 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. Changes to pipeline safety laws by Congress and regulations by PHMSA or states that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators.

For example, in March of 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements for calculating pressure reductions for immediate repairs on liquid pipelines. Also, in March 2016 PHMSA published a proposed rulemaking that would expand integrity management requirements and impose new pressure testing requirements on currently regulated pipelines. The proposal would also significantly expandthan the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits, and otherfederal requirements. The safety enhancement requirements and other provisions of the 2016 Pipeline Safety Act as well as any implementation of PHMSA, rules thereunder could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance

programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

Moreover, effective October 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations that occur after January 3, 2012 to $200,000 per violation per day and up to $2 million for a related series of violations. FederalThese federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and transportation costs of operation.due to constraints on available pipeline capacity, or reduce the price purchasers are willing to pay for our product.

We are subject to risks associated with climate change.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, adopted regulations under existing provisions of the federal Clean Air Actrules that among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permitpermitting reviews for certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meetfrom potential major sources of certain principal pollutant emissions, which reviews could require meeting “best available control technology” standards that will be established on acase-by-case basis. EPA rulemakings related to GHGfor air emissions, could adversely affect our operationsas well as monitoring and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring andannual reporting of GHG emissions from specified onshorecertain petroleum and offshore oilnatural gas system sources and, gas production sourcestogether with the National Highways Transportation Safety Administration, implement GHG emissions limits on vehicles manufactured for operation in the United States on an annual basis, which include certain of our operations. Recently, 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.States. The revisions also include the addition of well identification reporting requirements for certain facilities. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissionsregulation of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The BLM has also proposed rules to reduce methane emissions from venting, flaring, and leaking on public lands. As a result of this continued regulatory focus, future federal GHG regulations of the oil and gas industry remain a possibility.

In addition,sector has been subject to uncertainty in recent years. Prior standards were rescinded during the U.S. CongressTrump Administration; however, the current administration has from time to time considered adopting legislation to reducecalled for the reinstatement or issuance of methane emissions of GHGsstandards for new, modified, and a number of states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG capexisting oil and trade programs. Internationally, in December 2015,gas facilities. On an international level, the United States was one of many175 countries atto sign the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris France that prepared an agreement requiringAgreement, which requires member countries to review and “represent a progression” inset their nationally determined contributions which setown GHG emissionsemission reduction goals every five years. However, the GHG emission reductions called for by this Paris agreement are not binding and future participationbeginning in the agreement by2020. Although the United States athad withdrawn from the Paris Agreement, the current administration has recommitted the United States to the agreement and directed the federal government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement. The impacts of this time remains uncertain. The adoption oforder, and any legislation or regulatory programsregulation promulgated to reducefulfill the United States’ commitments under the Paris Agreement, are uncertain.

Forced emissions of GHGsreductions could require us to incur increasedincrease our operating costs such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatoryCapEx. Such programs could also increaseadversely affect the demand for natural gas by increasing the cost of consuming natural gas. Additionally, on January 27, 2021, the current administration called for substantial action on climate change, including, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and thereby reduceincreased emphasis on climate-related risks across agencies and economic sectors. Incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also adversely affect the demand for thenatural gas. Additionally, various state and local governments have brought suit against various oil and natural gas we produce.companies alleging damages related to climate

change or failure to properly disclose adverse climate impacts to their investors and consumers. Moreover, parties concerned about the potential effects of climate change have directed their attention at sources of funding for energy companies, which has resulted in certain financial institutions, funds and other sources of capital, restricting or eliminating their investment in oil and natural gas activities. There is also a risk that financial institutions will be required to adopt policies that have the effect of gradually curtailing the funding provided to the fossil fuel sector. Recently, the Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Consequently, legislation, and regulatory programsregulation, market changes, and/or future litigation related to reduce emissions of GHGsclimate change could have an adverse effect on our business, financial condition and results of operations. Finally, it should be noted that somebusiness. Further, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of hurricanes, storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial conditionadversely affect or delay demand for the natural gas we produce or cause us to incur significant costs in preparing for or responding to those effects. “Business— Regulation of Environmental and resultsOccupational Safety and Health Matters—Climate Change” contains further description of operations.the risks associated with climate change.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our operations are subject to risks associated with the energy industry, including the possibility of:

Any of these risks could adversely affect our operations and result in substantial loss to us for:

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, and if it is, its availability may be at premium levelscosts that do not justify its purchase. The occurrence of a significant uninsured claim or a claim in excess of the insurance coverage limits we maintain could have an adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us which liabilities maythat are not be covered by insurance.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield natural gas in commercially viable quantities.

Although we believe that the vast majority of our identified developmentdrilling locations are technically proved, any unsuccessful development ininability to develop commercially viable quantities will adversely affect our results of operations and financial condition. The use of micro-seismicseismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas will be present or, if present, whether natural gas will be present in commercial quantities. We can provide no assurance that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

In the future, we may make acquisitions of businesses that we believe complement or expand our current business. We may not be able to identify attractive acquisition opportunities or if we do, we may be unable to complete theany such acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired businessacquisition into our existing operations. The process of integrating acquired businessesacquisitions may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No

We can provide no assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assetsacquisitions into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our debt agreements impose certain limitations on our ability to enter into mergers or combination transactions and limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield 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 and technical personnel to conduct our operations can fluctuate significantly, often in correlation with hydrocarbon prices. We cannot predict whether these conditionsperiods of high demand will exist in the future and, if so, whator their timing and duration will be.duration. Furthermore, it is possible that oil prices may increase without a corresponding increase in natural gas prices, which could lead to increased demand and prices for supplies and personnel, and necessary equipment and services may become unavailable to us at economical prices. Any shortages in available human capital 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 or results of operations.

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

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is

substantial competition for capital available for investment in our industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased may increase

substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

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

We depend on the services of our senior management and technical personnel. Other than key man life insurance policies, weWe do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

Our business is difficult to evaluate because we have a limited operating history, and we are susceptible to the potential difficulties associated with rapid growth and expansion.

Our predecessor was organized as a Delaware limited partnership on May 28, 2014. As a result, our company has only limited historical financial and operating information available upon which to base your evaluation of our performance.

Events of force majeure may limit our ability to operate our business and could adversely affect our operating results.

The weather, unforeseen events, or other events of force majeure in the areas in which we operate could cause disruptions and, in some cases,or suspension of our operations. This suspension could result from a direct impact to our properties or result from an indirect impact by a disruption or suspension of the operations of those upon whom we rely for gathering and transportation. If disruption or suspension were to persist for a long period, our results of operations would be materially impacted.

Increases in interest rates could adversely affect our business.

We require continued access to capital. Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global energy capital markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

If commodity prices decrease and our assets’ fair value is less than their carrying value, we will recognize impairments.

We periodically review the carrying value of our assets for possible impairment. Natural gas prices are a critical component to our fair value estimate of our natural gas properties. If these prices decline, we will record an impairment, which is anon-cash charge to earnings, if we determine that an asset’s carrying value exceeds its estimated fair value. Impairment expense may have a material adverse effect on our earnings.

The enactment of derivatives legislation and related regulations could have had an adverse effect on our ability to use derivatives to hedge risks associated with our business.

TheTitle VII of the Dodd-Frank Act enacted on July 21, 2010, establishesestablished federal oversight and regulation of theover-the-counter derivatives market and entities, such asof companies like us that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing mandates of the Dodd-Frank Act.Act with respect to over-the-counter derivatives of the types we use to hedge our exposure to commodity price volatility. Although the CFTC has finalized someissued final regulations including critical rulemakings onin certain areas, in other areas, final regulations and the definitionscope of “swap,” “swap dealer,” and “major swap participant,” othersrelevant definitions and/or exemptions still remain to be finalized and it is not possible at this time to predict when this will be accomplished.finalized.

The Dodd-Frank Act authorized the CFTC to establish rules and regulations settingissued a final rule on October 15, 2020, imposing position limits for certain futures and option contracts in the major energy marketsvarious commodities (including oil and natural gas) and for swaps that are their economic equivalents. The CFTC’s initial positioncompliance dates for these limits rules were vacated by the U.S. District Court for the Districtare delayed until January 1, 2022 and in some cases, January 1, 2023. Under this rule, certain types of Columbia in September 2012. However, on November 5, 2013, the CFTC proposed new rules that would placehedging transactions are exempt from these limits on the size of positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptionsthat may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain bonaenumerated “bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.hedging” transactions or positions.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classesalso adopted a final rule regarding aggregation of swaps, including physical commodity swaps, for mandatory clearing. In addition, certain banking regulators andpositions, under which a party that controls the CFTC have recently adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for theend-user exception from the mandatory clearing, trade execution and margin requirements for swaps entered to hedge our commercial risks, the applicationtrading of, such requirements to other market participants, such as swap dealers, may change the cost and availabilityor owns 10% or more of the swaps that we useequity interests in, another party will have to aggregate the positions of the controlled or owned party with its own positions for hedging. If anypurposes of our swaps do not qualify fordetermining compliance with position limits unless an exemption applies. The CFTC’s aggregation rules are now in effect, though CFTC staff have granted relief—until August 12, 2022—from various conditions and requirements in the commercialend-user exception, postingfinal aggregation rules. With the implementation of collateral could impact liquiditythe final aggregation rules and reduce our cash available for CapEx, therefore reducingupon the effectiveness of the final CFTC position limits rule, our ability to execute hedges to reduce risk and protect cash flows.our hedging strategies described herein could be limited.”