What changed in this filing

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Item 1A. Risk Factors

2025-03-05 compared with 2024-03-06 · 212 added, 196 removed, 702 unchanged (37% of the section changed)

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Recent regulatory restrictions on use of produced water and a moratorium on new produced water disposal wells in certain areas of the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition.

The NMOCD and the RRC have each imposed stricter requirements for oil and gas wastewater injection activities in response to seismic activity in the Permian Basin.

For example, in November 2021, NMOCD implemented a “Seismicity Response Protocol” that imposes additional analysis, reporting, injection rate reduction or curtailment, and notification requirements on operators depending on the number and intensity of seismic events.

In September 2021, the RRC announced that it will not issue any new saltwater disposal (“SWD”) well permits in an area known as the Gardendale Seismic Response Area (“SRA”), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well.

In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits.

In October 2021, the RRC identified an additional SRA—the Northern Culberson-Reeves (“NCR”) SRA—and, in January 2022, the RRC identified still another SRA—the Stanton SRA.

Operators in the NCR and Stanton SRAs were required to implement seismic response plans, which include expanded data collection efforts,

contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff.

Both the Gardendale and NCR SRAs were expanded in December 2022 in response to additional earthquakes in the area and, effective January 12, 2024, the RRC suspended all (totaling 23) deep disposal well permits in the NCR SRA.

These actions were taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S.

and local seismologists to wastewater disposal in oil fields.

In recent years, the NMOCD and the RRC have each imposed stricter requirements for oil and gas wastewater injection activities in response to seismic activity in the Permian Basin, including the imposition of additional analysis, reporting, injection rate reduction or curtailment, and notification requirements on operators depending on the number and intensity of seismic events and in certain areas suspended issuance of new SWD well permits, as well as suspended or limited existing disposal well permits.

These actions have and are being taken in an effort to control induced seismic activity and recent increases in earthquakes in the Permian Basin, which have been linked by the U.S.

and local seismologists to wastewater disposal in oilfields.

These restrictions on the disposal of produced water and a moratorium on new produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or dispose of it by other means, all of which could be costly.

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Enhanced scrutiny on ESG matters could have an adverse effect on the Company’s operations.

Enhanced scrutiny on ESG matters related to, among other things, concerns raised by advocacy groups about climate change, hydraulic fracturing, natural gas flaring, GHG emissions, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations.

Enhanced scrutiny on ESG matters related to, among other things, concerns raised by investors and advocacy groups about climate change, hydraulic fracturing, natural gas flaring, GHG emissions, waste disposal, oil spills, and explosions of natural gas transmission pipelines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines, and enforcement interpretations.

These concerns and actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens, increased risk of litigation, and adverse impacts on the Company’s access to capital.

Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance, and the public may engage in the permitting process, including through intervention in the courts.

Negative public perception could cause the permits the Company requires to conduct its operations to be withheld, delayed, or burdened by requirements that restrict the Company’s ability to profitably conduct its business.

Negative public perception could cause the permits the Company requires to conduct our operations to be withheld, delayed, or burdened by requirements that restrict the Company’s ability to profitably conduct our business.

We may be unable to quickly adapt to changes in market/investor priorities.

Historically, one of the key drivers in the unconventional resource industry has been growth in production and reserves.

With historical volatility in oil and natural gas prices and the likelihood that rising interest rates will increase the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale producers.

With historical volatility in oil and natural gas prices and the potential for rising interest rates will increase the cost of borrowing, capital efficiency and free cash flow from earnings have become the key drivers for energy companies, particularly shale producers.

Such shifts in focus sometimes require changes in planning and resource management, which may not occur instantaneously.

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Historically, the commodities market has been volatile.

For example, during the period from January 1, 2016 to December 31, 2023, NYMEX West Texas Intermediate (referred to as WTI) oil prices ranged from a high of $123.64 per Bbl on March 8, 2022 to a low of $(36.98) per Bbl on April 20, 2020.

During 2023, WTI prices ranged from a high of $93.67 to a low of $66.61 per Bbl.

For example, during the period from January 1, 2016 to December 31, 2024, NYMEX WTI oil prices ranged from a high of $123.64 per Bbl on March 8, 2022 to a low of negative $36.98 per Bbl on April 20, 2020.

During 2024, WTI prices ranged from a high of $87.69 per Bbl to a low of $66.73 per Bbl.

Average daily prices for NYMEX Henry Hub gas ranged from a high of $13.20 per MMBtu to a low of $1.21 per MMBtu during 2024.

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

• private and government investment in and regulatory incentives for non-fossil fuel energy production;

• private and government investment in, regulatory incentives for, and purchaser and consumer preferences for non-fossil fuel energy production;

• changes in applicable laws and regulations;

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• the price and availability of alternative fuels;

• domestic, local, and foreign governmental regulation and taxes.

• domestic, local, and foreign governmental regulation, taxes and tariffs.

Lower commodity prices will reduce our cash flows and borrowing ability.

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A write down constitutes a non-cash charge to earnings.

If market or other economic conditions deteriorate or if oil, natural gas and NGL prices decline, we may incur impairment charges, which may have a material adverse effect on our results of operations.

During the year ended December 31, 2023, the Company recognized an impairment loss on proved properties relating to certain properties in Texas outside of the Company's acreage in the Champions Field.

The impairment was primarily driven by notably lower commodity pricing at the time of measurement of fair value at year-end 2023.

Our exploration and development projects require substantial capital expenditures.

If market or other economic conditions deteriorate or if oil, natural gas and NGL prices decline, we may incur impairment losses, which may have a material adverse effect on our results of operations.

During the year ended December 31, 2024, the Company recognized impairment losses on proved properties relating to certain properties in Texas outside of the Company's acreage in the Champions field and certain properties in New Mexico outside of the Company's acreage in the Red Lake field.

The impairments were primarily driven by a reduction in reserve volume due to lower well performance assessments based on historical trends.

The affected areas included nine operated producing wells.

Our exploration, development and midstream projects require substantial capital expenditures.

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

The oil and natural gas industry is capital intensive.

We make and expect to continue to make substantial capital expenditures for the exploitation, development, and acquisition of oil and natural gas reserves.

We make and expect to continue to make substantial capital expenditures for the exploration, exploitation, development and acquisition of oil and natural gas reserves and the construction of midstream gathering, compression and pipeline facilities.

We expect to fund our growth primarily through cash flow from operations, availability under our Credit Facility, and subsequent equity or debt offerings when appropriate.

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, regulatory, technological and competitive developments, and worldwide and regional economic conditions.

The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, construction delays in our midstream project, cost of materials, regulatory, technological and competitive developments, and worldwide and regional economic conditions.

A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

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• the prices at which our production is sold;

• operating costs and other expenses;

• operating, maintenance and general and administrative costs and other expenses;

• the availability of takeaway capacity;

• the level and timing of maintenance and expansion capital expenditures we make;

• required regulatory and third-party approvals;

• availability and cost of third-party service providers;

• regulatory action affecting the supply of, or demand for, hydrocarbons and the rates that we can charge for our production;

• the availability and price of alternative and competing fuel sources, the rates of growth of alternative energy sources and the consumer adoption of alternative energy sources;

• Credit Facility and/or investor requirements;

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• adverse weather conditions;

• compliance with environmental and other governmental or contractual requirements;

• compliance with environmental, health and safety, and other governmental or contractual requirements;

• increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

The construction of our planned New Mexico natural gas gathering, compression and pipeline projects are subject to a number of development risks, which could cause cost overruns and delays or prevent completion of one or more of our midstream development projects.

Key factors that may affect the timing of, and our ability to complete, our midstream development projects include, but are not limited to:

• the issuance and/or continued availability of necessary permits, licenses and approvals from governmental agencies and third parties as are required to construct, own and operate the facilities, including right-of-way agreements;

• the availability of sufficient financing;

• our ability to maintain an engineering, procurement and construction (“EPC”) services agreement with an EPC contractor for each phase of the construction on favorable terms, and to maintain good relationships with these contractors, and the ability of those EPC contractors to perform their obligations under EPC agreements and to maintain their creditworthiness;

• site development difficulties, including change orders, cost overruns, and construction delays;

• competition for EPC contractors with other gas gathering, compression and pipeline service companies;

• increases in the cost of materials due to inflation, taxes, tariffs, or other economic conditions or government or third party actions;

• continued commercial arrangements for gathering, processing and treating our natural gas until our pipeline in-service date under our new gas purchase agreement;

• local and general economic conditions;

• catastrophes, such as explosions, fires and product spills;

• resistance in the local community to the development of midstream infrastructure assets, including the pipeline;

• contract labor disputes;

• weather conditions.

Delays in the construction of the gathering, compression and natural gas pipeline beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts currently estimated in our capital budget, which could require us to obtain additional sources of financing to complete the construction (which could cause further delays) and could delay the development of our New Mexico oil and gas properties.

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

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Actual future prices and costs may differ materially from those used in the present value estimate.

For example, our estimated proved reserves as of December 31, 2023 were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $78.22 per Bbl for oil and NGL volumes and $2.64 per MMBtu for natural gas volumes.

For example, our estimated proved reserves as of December 31, 2024, were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $76.32 per Bbl for oil and NGL volumes and $2.13

per MMBtu for natural gas volumes.

Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.

There is a limited amount of production data from horizontal wells completed in the Permian Basin and its San Andres Formation.

As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.

There is a limited amount of production data from horizontal wells completed in the Permian Basin and its Yeso and San Andres Formations.

As a result, reserve estimates associated with horizontal wells in these areas are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.

Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field.

Horizontal drilling in the San Andres Formation of the Permian Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in this area for over 50 years.

Horizontal drilling in the San Andres and Yeso Formations of the Permian Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in these areas for over 50 years.

As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small compared to that of production data from vertical wells.

Until a greater number of horizontal wells have been completed in the San Andres Formation, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the

transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories.

Until a greater number of horizontal wells have been completed in the Yeso and San Andres Formations, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories.

Such variance could be material and any such variance could have a material and adverse impact on our cash flows and results of operations.

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Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers.

As of December 31, 2023, we had drilled and completed 517 gross operated horizontal wells on our West Texas an d New Mexico acreage, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities.

As of December 31, 2024, the Company produced from 782 gross wells on our West Texas an d New Mexico acreage, of which 228 are horizontal wells, and therefore are subject to increased risks associated with horizontal drilling.

Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore.

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Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Approximate ly 6% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein.

In addition, leases may also be lost due to legal issues relating to the ownership of leases.

Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth.

As of December 31, 2023, approximately 6% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would pe rmit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Unless production is established on the undeveloped acreage covered by our leases, such leases will expire.

Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our drilling plans are subject to change based upon various factors, including factors that are beyond our control.

Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.

If our leases expire, we will lose our right to develop such properties.

Substantially all of our producing properties are located in the Northwest Shelf within the Permian Basin of West Texas and Southeastern New Mexico, making us vulnerable to risks associated with operating in one major geographic area.

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Access to such facilities is, in many respects, beyond our control.

If these facilities are unavailable to us on commercially reasonable terms or otherwise (either temporarily or long-term), we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons, as was the case in July and August 2023 when our producing wells in the Redlake field in New Mexico were shut in due to an unexpected maintenance issue with our third party processing plant.

We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit, and sell our oil and natural gas production.

If these facilities are unavailable to us on commercially reasonable terms or otherwise (either temporarily or long-term), we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons, as was the case in July and August 2023 and in July 2024 when our producing wells in the Red Lake field in New Mexico were shut in due to unexpected maintenance issues with our third party processor.

We rely on facilities developed and owned by third parties in order to store, process, transmit, and sell our oil and natural gas production, and even once our planned gathering, compression and pipeline projects are completed, we still expect to rely on third-party facilities.

Until our planned pipeline is constructed to connect with our new midstream counterparty's facilities, we are operating under a month-to-month arrangement with our current midstream counterparty, which could be terminated at any time.

Our plans to develop and sell our oil and natural gas reserves, the expected results of our drilling program and our cash flow and results of operations could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise.

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For example, production increases from competing Permian Basin producers, combined with limited pipeline and transportation capacity in the area, have gradually widened differentials in the Permian Basin.

For the year ended December 31, 2023, our realized oil differential to NYMEX WTI averaged $(1.96) per Bbl of oil and our realized natural gas differential to NYMEX Henry Hub averaged $(2.08) per Mcf of gas.

For the year ended December 31, 2024, our realized oil differential to NYMEX WTI averaged negative $2.53 per Bbl of oil and our realized natural gas differential to NYMEX Henry Hub averaged negative $2.38 per Mcf of gas.

Given that a significant amount of our production is from the Permian Basin, if the negative price differential in the Permian Basin increases, we expect that the effect of our price differential on our revenues will also increase.

Increases in the differential between the benchmark prices for oil and natural gas, such as the NYMEX WTI and NYMEX Henry Hub, and the realized price we receive could significantly reduce our revenues and our cash flow from operations.

Increases in the negative price differential between the benchmark prices for oil and natural gas, such as the NYMEX WTI and NYMEX Henry Hub, and the realized price we receive could significantly reduce our revenues and our cash flow from operations.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.

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A t December 31, 2024, approximately 38% of our total estimated proved reserves were classified as proved undeveloped.

Our approximate 47,537 MBoe of estimated proved undeveloped reserves are estimated to require $322.7 million of development capital.

Our approximate 46,956 MBoe of estimated proved undeveloped reserves are estimated to require approximately $279 million of development capital.

Our development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate.

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As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all.

For example, we cannot control the success of drilling and development activities on

properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology.

For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology.

In addition, the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control.

A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

A third-party operator’s failure to adequately perform operations, non-compliance with applicable regulatory, environmental, and permitting requirements, breach of the applicable agreements, or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

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

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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.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production.

We depend upon a few significant purchasers for the sale of most of our oil and natural gas production.

The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGLs we produce.

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce.

In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production.

In addition, we depend upon a few significant purchasers for the sale of most of our oil and natural gas production.

We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

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Losses and liabilities arising from uninsured and under insured events could materially and adversely affect our business, financial condition or results of operations.

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering or other cratering, uncontrollable flows of natural gas, oil, well fluids and formation water, pipe or pipeline failures, processing or transportation capacity constraints or disruptions, abnormally pressured formations, casing collapses, reservoir damage and environmental hazards such as oil, produced water or chemical spills, natural gas leaks, ruptures or discharges of toxic gases.

Our activities are subject to all of the operating risks associated with drilling for, producing, gathering and compressing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering or other cratering, uncontrollable flows of natural gas, oil, well fluids and formation water, pipe or pipeline failures, processing or transportation capacity constraints or disruptions, damages to pipelines, compressor stations and related equipment, abnormally pressured formations, casing collapses, reservoir damage and environmental hazards such as oil, produced water or chemical spills, natural gas leaks, ruptures or discharges of toxic gases.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

• injury or loss of life;

• exposure to or release of hazardous substances;

• medical monitoring;

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• abnormally pressured formations, fires or explosions or natural disasters;

• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

• regulatory investigations and penalties;

• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

• regulatory investigations, injunctions, fines, and penalties;

• landowner claims for property damage and restoration costs;

• suspension of our operations;

• repair and remediation costs.

• repair, corrective action, and remediation costs.

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.

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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 assets 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.

Our failure to achieve consolidation savings, to integrate the acquired businesses and assets 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 Credit Facility imposes certain limitations on our ability to enter into mergers or combination transactions as well as limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

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Additionally, any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.

Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production or by other operations.

Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production or by other methods.

In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire.

As of December 31, 2023, 43% of our net undeveloped acreage is set to expire in 2024, before taking into account the expected drilling of wells and holding leases by production, while 4% of our net undeveloped acreage is set to expire through 2024, after taking into account the expected drilling of wells and holding leases by production.

We intend to extend or renew any core lease we plan to develop or are still assessing for development that is set to expire in 2024 and expect to incur $0.2 million to extend or renew those leases, after taking into account the expected drilling of wells and holding leases by production.

Where we do not have the option to extend a lease, however, we may not be successful in negotiating extensions or renewals.

Our ability to drill and develop our core acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire.

The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all.

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These risks are greater at times and in areas where the pace of our exploration and development activity slows.

We plan to use CO 2 for our EOR projects.

Our production from these EOR operations may decline if we are not able to obtain sufficient amounts of CO 2 .

Oil production from our EOR projects depends on, among other factors, having access to sufficient amounts of CO 2 from our third-party suppliers of CO 2 .

Our ability to produce oil from our EOR projects would be hindered if the supply of CO 2 was limited due to, among other things, physical limitations on CO 2 supply or the ability to economically procure CO 2 at costs low enough to ensure the economic viability of our EOR projects.

This could have a material adverse effect on our financial condition, results of operations or cash flows.

Future oil production from the Company’s EOR projects is dependent on the timing, volumes and location of CO 2 injections and, in particular, our ability to obtain sufficient volumes of CO 2 .

Market conditions may cause the delay or cancellation of the development of naturally occurring CO 2 sources or construction of plants that produce anthropogenic CO 2 as a byproduct that can be purchased, thus limiting the amount of CO 2 available for use in our EOR projects.

As of December 31, 2024, approximately 5% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage contains proved reserves.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

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Our future results will suffer if we do not effectively manage our expanded operations.

As a result of our recent acquisitions, the size and geographic footprint of our business has increased.

As a result of our recent acquisitions, the size of our business has increased.

Our future success will depend, in part, upon our ability to manage this expanded business, which may pose substantial challenges for management, including challenges related to the management and monitoring of new operations and basins and associated increased costs and complexity.

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We may need to access funding through capital market transactions.

Due to our small public float, low market capitalization, limited operating history, ESG, and climate change restrictions, it may be difficult and expensive for us to raise additional funds.

Due to our relative smaller public float and low market capitalization, ESG, and climate change policies and restrictions, it may be difficult and expensive for us to raise additional funds.

We may need to raise funds through the issuance of shares of our common stock or securities linked to our common stock.

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Our Credit Facility and our Senior Notes have substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.

The operating and financial restrictions and covenants in our Credit Facility and our Senior Notes restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand or pursue our business activities or pay dividends.

business activities or pay dividends.

Our Credit Facility and our Senior Notes restrict, and any future financing agreements likely will restrict, our ability to, among other things:

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Any such sale could have a material adverse effect on our business and financial results.

In the future, we may not be able to access adequate funding under our Credit Facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or 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 the defaulting lender’s portion.

additional funding to cover the defaulting lender’s portion.

Declines in commodity prices could result in a redetermination and reduction of the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the reduced borrowing base.

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In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so.

Any drilling activities we are able to

conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Our derivative activities could result in financial losses or could reduce our earnings.

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If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

Our construction of new gathering, compression and pipeline assets may not be completed on schedule, at the budgeted cost or at all, may not operate as designed or at the expected levels, may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, all of which could adversely affect our financial condition, cash flows and results of operations.

The construction of the new midstream infrastructure assets involves numerous regulatory, environmental, political and legal requirements as well as legal uncertainties beyond our control and may require the expenditure of significant amounts of capital and resources.

Financing may not be available on economically acceptable terms or at all.

If we undertake these projects, we may not be able to complete them on schedule, at the budgeted cost or at all, or they may not operate as designed or at the expected levels.

In addition, we may construct facilities to capture anticipated future production growth in an area in which such growth does not materialize, which could adversely affect our financial condition and results of operations.

In addition, construction of new midstream infrastructure assets may require us to obtain new rights-of-way prior to constructing the New Mexico pipeline and/or related facilities.

We may be unable to timely obtain such rights-of-way to connect new natural gas supplies to our existing gathering pipelines or capitalize on other attractive expansion opportunities.

Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way.

If the cost of renewing or obtaining new rights-of-way increases, our results of operations could be adversely affected.

The regulatory approval process for the construction of new midstream assets is challenging.

Certain of our internal growth projects require regulatory approval from federal, tribal, state and/or local authorities prior to construction, including the construction of certain of our planned midstream facilities.

The approval process for natural gas pipeline projects has become increasingly challenging, due in part to state and local concerns related to exploration and production, transmission, and gathering activities in production areas and negative public perception regarding the oil and gas industry.

Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.

In addition, any significant delays in the regulatory approval process for our midstream facilities could increase the costs and negatively impact the targeted in-service date for the facilities, which in turn could adversely impact our business, results of operations and financial condition.

We may face opposition to the development or operation of our midstream facilities from various groups.

We may face opposition to the development or operation of our midstream facilities from environmental groups, landowners, local and national groups, activists and other advocates.

Such opposition could take many forms, including organized protests, attempts to block, vandalize or sabotage our development or operations, intervention in regulatory or administrative proceedings involving our assets directly or indirectly, lawsuits, legislation or other actions designed to prevent, disrupt or delay the development or operation of our assets and business.

For example, constructing our pipelines will involve securing consent from individual landowners to access their property;

one or more landowners may restrict our access, which could lead to an interruption or delay in the construction of our facilities.

In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations.

Any such event that delays or interrupts the revenues generated, or expected to be generated, by our operations, or which causes significant delays or causes us to make significant expenditures not covered by insurance, and, accordingly, could adversely affect our financial condition and the market price of our securities.

The midstream infrastructure buildout projects we complete may not perform as anticipated.

Even if we complete the planned midstream infrastructure buildout projects that we believe will be strategic , such projects may nevertheless adversely impact our business, results of operations and financial condition due to the following factors, among others:

• mistaken assumptions about capacity, revenues, synergies, costs (including operating and administrative, capital, debt and equity costs), inflation, growth potential, assumed liabilities and other factors;

• the failure to receive cash flows from a growth project due to delays in the commencement of operations for any reason;

• unforeseen operational issues or the realization of liabilities that were not known to us at the time the growth project was completed;

• the failure to successfully integrate growth projects into our operations and/or the loss of key employees;

• the impact of regulatory, environmental, political and legal uncertainties, extreme weather or force majeure events, that are beyond our control.

In particular, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize.

As a result, new facilities may not be able to generate enough throughput to accomplish our development plan for our New Mexico assets, which could adversely affect our business, financial condition, results of operations and ability to make distributions.

If we complete future growth projects, our capitalization and results of operations may change significantly, and our investors may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

If any growth projects we ultimately complete are not accretive, our business, results of operations and financial condition may be negatively impacted.

We do not own all of the land on which our pipelines and facilities are located or planned, which could result in disruptions to our operations.

Because we do not own all of the land on which our pipelines and facilities have been or are planned to be constructed, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate.

We obtain or expect to obtain the rights to construct and operate our pipeline on land owned by third parties and governmental agencies for a specific period of time.

Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations.

If third-party pipelines, other midstream facilities or purchasers of our products interconnected to our gathering or pipeline systems become partially or fully unavailable, or if the volumes we gather, process or transport do not meet the natural gas and NGL quality requirements of such pipelines or facilities, our business, results of operations and financial condition could be adversely impacted.

Our natural gas gathering and pipelines will connect to other pipelines or facilities owned and operated by unaffiliated third parties.

The continuing operation of such third-party pipelines, processing and treatment plants, facilities of purchasers of our products and other midstream facilities is not within our control.

These pipelines and facilities may become unavailable because of testing, turnarounds, line repair, or maintenance, failure to meet product specifications, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from natural disasters or other operational hazards.

If any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes we gather do not meet the natural gas quality requirements (such as hydrocarbon dew point, temperature and foreign content including water, sulfur, carbon dioxide and hydrogen sulfide) of such pipelines or facilities, our business, results of operations and financial condition could be adversely affected.

Our joint ventures may not perform as expected, and conducting a portion of our operations through joint ventures in which we do not have 100% ownership interest exposes us to risks and uncertainties, many of which are outside of our control.

In January 2023, we formed a joint venture, RPC Power, in which we initially held a 35% interest and increased our equity ownership to 50% in May 2024.

We have entered into and may also enter into in the future additional joint ventures or other equity investments in the future in which we may not have 100% ownership interest.

We may not realize any of the anticipated benefits of our joint ventures or other equity investments.

Challenges and risks presented by joint venture structures not otherwise present with respect to our wholly-owned subsidiaries and direct operations, include:

• our joint ventures may fail to generate the expected financial results, and the return may be insufficient to justify our investment of effort and/or funds;

• we may not control the joint ventures or our venture partners may hold veto rights over certain actions;

• the level of oversight, control and access to management information we are able to exercise with respect to these operations may be lower compared to our wholly-owned businesses, which may increase uncertainty relating to the financial condition of these operations, including the credit risk profile;

• we may experience impasses or disputes with our joint venture partners on certain decisions, which could require us to expend additional resources to resolve such impasses or disputes, including litigation or arbitration;

• we may not have control over the timing or amount of distributions from the joint ventures;

• our joint venture partners may have business or economic interests that are inconsistent with ours and may take actions contrary to our interests;

• our joint ventures may enter into business outside of our core business exposing us to unforeseen risks;

• our joint venture partners may become insolvent or bankrupt, or may otherwise fail to fund capital contributions or fail to fulfill their obligations as partners, which may require us to infuse our own capital into the venture or seek additional financing;

• the arrangements governing our joint ventures may contain restrictions on the conduct of our business and may contain certain conditions or milestone events that may never be satisfied or achieved;

• we may suffer losses as a result of actions taken by our venture partners with respect to our joint ventures;

• our joint venture partners may experience a change of control or a change in management, which could adversely impact the relationship between the joint venture partners and us;

• it may be difficult for us to exit joint ventures if an impasse arises or if we desire to sell our interest for any reason;

• we may be forced to sell our interest or acquire our partner’s interest at time we otherwise would not have elected to do so as a result of the arrangements governing our joint ventures.

Joint venture partners, controlling equity holders, management or other persons or entities who control them may have economic or business interests, strategies or goals that are inconsistent with ours.

Business decisions or other actions or omissions of the joint venture partners, controlling equity holders, management or other persons or entities who control them may adversely affect the value of our investment, result in litigation or regulatory action against us and otherwise damage our reputation.

Any such circumstance could materially adversely affect our results of operations, financial condition, cash flows and/or prospects.

Risks Related to the Oil and Natural Gas Industry

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• environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the air, surface and subsurface environment;

• issues related to permitting under and compliance with environmental and other governmental regulations;

• issues or challenges related to permitting under and compliance with environmental and other governmental regulations;

• declines or volatility in oil, natural gas, and NGL prices;

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Our operations are concentrated in areas in which activity has increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items.

In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted if the United States imposes tariffs on imported goods from countries

where these goods are produced.

Such shortages or cost increases 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.

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In addition, a decline in consumer confidence or changing patterns in the availability and use of disposable income by consumers can negatively affect the demand for oil and natural gas as a result of our results of operations.

Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases to the cost of our goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

Inflationary issues and associated changes in monetary policy have resulted in and may in the future result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

Inflation has been an ongoing concern in the U.S.

Ongoing inflationary pressures have resulted in and may result in additional increases to the costs of goods, services and personnel, which in turn cause our capital expenditures and operating costs to rise.

Sustained levels of high inflation caused the U.S.

Federal Reserve and other central banks to increase interest rates beginning in 2022 and continuing in 2023 in an effort to curb inflationary pressure on the costs of goods and services, which could have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.

We may experience further cost increases for our operations to the extent that elevated inflation remains.

in recent years.

Although inflation moderated somewhat in 2024, inflationary pressures have resulted in and may in the future result in additional increases to the costs of goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

During inflationary periods, interest rates have historically increased.

Increased interest rates could have the effects of raising the cost of capital and depressing economic growth, either of which (or the combination thereof) could hurt the financial and operating results of our business.

In 2024, while rates were slightly decreased, they remained elevated as the U.S.

Federal Reserve and other central banks continued to navigate inflationary concerns.

We may experience further cost increases for our operations to the extent that there are increases in inflationary pressures or interest rates.

We may not be able to keep pace with technological developments in our industry.

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Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, seismic activity, greenhouse gas emissions, and explosions of natural gas

transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil or produced water spills, groundwater contamination, seismic activity, greenhouse gas emissions, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations.

These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation.

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Extreme weather conditions could adversely affect our ability to conduct drilling and production activities in the areas where we operate.

Our exploration, exploitation, development, and production activities and equipment could be adversely affected by extreme weather conditions, such as floods, lightening, drought, ice and other storms, prolonged freeze events, and tornadoes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment.

Our exploration, exploitation, development, and production activities and equipment could be adversely affected by extreme weather conditions, such as floods, lightning, drought, ice and other storms, prolonged freeze events, and tornadoes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment.

Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services, such as electrical power, water, gathering, processing, compression, transportation, and produced water disposal services.

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Risks Related to Legal, Regulatory, and Tax Matters

We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental and human health and safety protection.

These laws and regulations may impose numerous obligations applicable to our operations including (i) the acquisition of a permit before conducting drilling, production, and other regulated activities;

(ii) the restriction of types, quantities and concentration of materials that may be released into the environment;

(iii) the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, protected species habitat, and other sensitive or protected areas;

(iv) the application of specific health and safety criteria addressing worker protection;

(v) the imposition of substantial liabilities for pollution resulting from our operations;

(vi) the installation of costly emission monitoring and/or pollution control equipment;

and (vii) the reporting of the types and quantities of various substances that are generated, stored, processed, transported, disposed, or released in connection with our properties.

We are subject to stringent federal, tribal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our operations are subject to stringent federal, tribal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental and human health and safety protection.

Numerous governmental authorities, such as the EPA, the U.S.

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Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions.

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.

Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal fines and 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 or specific projects and limit our growth and revenue.

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 at our leased and owned properties, as well as locations where waste from our operations is transported offsite for disposal.

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 subject to strict, joint and several liability for the removal or remediation of previously released 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.

We may not be able to recover some or any of these costs from insurance.

Changes in environmental laws and regulations occur frequently and tend to become more stringent over time, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control 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 results of

operations, competitive position or financial condition.

For example, on October 1, 2015, the EPA issued a final rule under the CAA, lowering the NAAQS for ground-level ozone from the current standard of 75 parts per billion, or ppb, for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards.

Subsequently, the EPA designated over 200 counties across the U.S.

as “nonattainment” for these standards, meaning that new and modified stationary emissions sources in these areas are subject to more stringent permitting and pollution control requirements.

On December 23, 2021, the EPA announced its decision to retain, without changes, the 2015 NAAQS.

On August 21, 2023, EPA announced the initiation of a new review of the ozone NAAQS to ensure the standards reflect the most current, relevant science.

EPA’s review is ongoing.

If our operations become subject to these more stringent standards, compliance with these and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant.

Changes in environmental and health and safety laws and regulations occur frequently and tend to become more stringent over time, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, worker protection, air emissions control 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 results of operations, competitive position or financial condition.

See “Items 1 and 2 Business and Properties – Regulation of the Oil and Natural Gas Industry” for additional detail on environmental laws and regulations.

If our operations become subject to more stringent standards, compliance with these and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

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Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

We are responsible for the decommissioning, surface equipment removal, plugging, abandonment, and reclamation costs for our facilities.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, surface equipment removal, plugging, 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, surface equipment removal, plugging, 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, surface equipment removal, plugging, abandonment, and reclamation reserve funds to provide for payment of future decommissioning, surface equipment removal, plugging, 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, surface equipment removal, plugging, abandonment, and reclamation costs and we will be responsible for the payment of the balance of such costs.

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

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, removal, plugging, 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, removal, plugging, 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, removal, plugging, abandonment, and reclamation reserve funds to provide for payment of future decommissioning, removal, plugging, 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, removal, plugging, abandonment, and reclamation costs and we will be responsible for the payment of the balance of such costs.

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

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Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation.

FERC may also impose administrative and criminal remedies and

disgorgement of profits associated with any violation.

FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation.

While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements.

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Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time.

Additionally, our planned midstream project could subject us to regulation by FERC or New Mexico state regulators.

Additionally, the Federal Trade Commission (the “FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1.0 million per day, and the CFTC, prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales.

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Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Gas Industry.”

A change in the jurisdictional characterization of our natural gas assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our natural gas assets, which may cause our revenues to decline and operating expenses to increase.

A change in the jurisdictional characterization of our natural gas assets or planned midstream project by federal, tribal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our natural gas assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC.

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The distinction between FERC-regulated transmission services and gathering services not subject to the jurisdiction of FERC, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering 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 FERC, the courts or Congress.

If FERC were to consider the status of an individual facility and determine that the facility 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 FERC under the NGA or the NGPA.

If FERC were to consider the status of an individual facility, including the new midstream project we plan to construct, and determine that the facility 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 FERC under the NGA or the NGPA and/or state regulations.

Such regulation could decrease revenue and increase operating costs.

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FERC regulation may indirectly impact gathering services not directly subject to FERC regulation.

FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets.

FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access

transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets.

In recent years, FERC has pursued procompetitive policies in its regulation of interstate natural gas pipelines.

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Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

The Department of Transportation has adopted regulations requiring pipeline operators to develop integrity management programs for pipelines located where a leak or rupture could do the most harm in HCAs.

The regulations require operators to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact an HCA;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary;

• implement preventive and mitigating actions.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”), among other things, increased the maximum civil penalty for pipeline safety violations and directed the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in HCAs.

Consistent with the 2011 Pipeline Safety Act, the Pipelines and Hazardous Materials Safety Administration (“PHMSA”), finalized rules consistent with the signed act that increased the maximum administrative civil penalties for violations of the pipeline safety laws and regulations to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations.

As of December 2023, those maximum civil penalties were increased to $266,015 and $2,660,135, respectively, to account for inflation and have remained at those rates.

Should our operations fail to comply with DOT or comparable state regulations, we could be subject to substantial penalties and fines.

We may be involved in legal proceedings that could result in substantial liabilities.

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Accruals for such liability, penalties or sanctions may be insufficient.

Judgments and estimates to determine

accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

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Hydraulic fracturing is typically regulated by state oil and natural gas commissions.

However, several federal agencies have asserted regulatory authority over certain aspects of the process.

For example, in February 2014, the EPA asserted regulatory authority pursuant to the SDWA UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities.

Also, beginning in 2012, the EPA issued a series of regulations under the federal CAA that include NSPS, known as Subpart OOOO, for completions of hydraulically fractured natural gas wells and certain other plants and equipment and, in May 2016, published a final rule establishing new emissions standards, known as Subpart OOOOa, for methane and volatile organic compounds (“VOCs”) from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category.

The NSPS Subpart OOOO and OOOOa rules have since been subject to numerous legal challenges as well as EPA reconsideration proceedings and subsequent amendment proposals.

More recently, in December 2023, EPA announced additional final NSPS OOOO program rules—referred to as Subparts OOOOb and OOOOc—which, once effective upon publication in the Federal Register, are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective.

Legal challenges to the expanded NSPS Subpart OOOO program rules are likely to follow, and accordingly, legal uncertainty exists with respect to the future scope and extent of implementation of the methane rule;

however, even as currently implemented, these rules apply to our operations, including requirements for the installation of equipment to control VOC emissions from certain hydraulic fracturing of wells and fugitive emissions from well sites and other production equipment.

Additional regulation could result in significant costs, including increased capital expenditures and operating and compliance costs, and could adversely impact or delay oil and natural gas production activities, which could have a material adverse effect on our business.

The BLM published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands.

However, following years of litigation, the BLM rescinded the rule in December 2017.

BLM’s repeal of the rule was challenged in court, and in March 2020, the Northern District of California issued a ruling in favor of the BLM.

This ruling was appealed, but the case has been administratively closed since November 15, 2021.

The regulations, if reinstated, may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase costs of compliance.

In addition, in May 2022, the U.S.

Government Accountability Office released a study on methane emissions from oil and gas development, which included a recommendation that the BLM consider whether to require gas capture plans, including gas capture targets, from operators on federal lands.

The reinstatement of the BLM hydraulic fracturing regulations or the promulgation of BLM gas capture regulations may result in additional levels of regulation or complexity that could lead to operational delays and increased operating and compliance costs that could make it more difficult and costly to perform hydraulic fracturing on federal and Indian lands.

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.

The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that certain hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts.

Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.

From time to time, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, to date, such legislation has not been adopted.

At the state level, Texas, where we conduct most of our operations, is among the states that has adopted regulations that impose new or more stringent permitting, including the requirement for hydraulic-fracturing operators to complete and submit a list of chemicals used during the fracking process.

We may incur significant additional costs to comply with such existing state requirements and, in the event additional state level restrictions relating to the hydraulic-fracturing process are

adopted in areas where we operate, we may become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Moreover, we typically dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in underground disposal wells.

This disposal process has been linked to increased induced seismicity events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas.

These and other states have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing these requirements may issue orders directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring.

NMOCD and RRC have each imposed requirements in response to seismic events in the Permian Basin.

See “Recent regulatory restrictions on use of produced water and a moratorium on new produced water disposal wells in certain areas of the Permian Basin to stem rising seismic activity and earthquakes could increase our operating costs and adversely impact our business, results of operations and financial condition." Any one or more of these developments may result in our having to limit disposal well volumes, disposal rates or locations, or to cease disposal well activities, or comply with more stringent analysis, recordkeeping, and notification requirements, which could have a material adverse effect on our business, financial condition, and results of operations.

However, several federal and local agencies have also adopted, or are considering adopting, regulations that

could further 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.

See “Items 1 and 2 Business and Properties – Regulation of the Oil and Natural Gas Industry”.

Increased regulation and attention given to the hydraulic fracturing process and associated processes could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques.

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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 GHGs.

While no comprehensive climate change legislation has been implemented at the federal level, the EPA and states or groupings of states have pursued legal initiatives in recent years that seek to reduce GHG emissions through efforts that include consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

In particular, the EPA has adopted rules under authority of the CAA that, among other things, establish certain permit reviews for GHG emissions from certain large stationary sources, which reviews could require securing permits at covered facilities emitting GHGs and meeting defined technological standards for those GHG emissions.

The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore production.

And, more recently, in August 2022, Congress passed the IRA, which includes requirements to impose fees beginning in 2025 on methane emissions from oil and gas operations that are required to report their GHG emissions under the EPA’s GHG Reporting Rule.

Federal agencies also have begun directly regulating emissions of methane and GHG from oil and natural gas operations.

In June 2016, the EPA published a final rule establishing NSPS Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions.

Furthermore, in November 2021 and November 2022, the EPA issued proposed rules which would update, strengthen, and expand the NSPS Subpart OOOO regulations for methane and VOC emissions from new, modified, and reconstructed sources.

EPA has since announced in December 2023 the final version of these proposed rules, which are to be codified as NSPS Subparts OOOOb and OOOOc.

Notably, the NSPS Subpart OOOOc rules include emissions guidelines to assist states in the development of plans to regulate methane emissions from certain existing sources, which had not previously been regulated under the NSPS Subpart OOOO programs.

Legal challenges to the recently announced final NSPS Subparts OOOOb and OOOOc rules are likely to follow, and thus, the ultimate scope of these regulations remains uncertain.

However, once effective upon publication in the Federal Register, the NSPS Subparts OOOOb and OOOOc rules are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective.

The BLM also finalized rules regarding the control of methane emissions in November 2016 that applied to oil and natural gas exploration and development activities on public and tribal lands.

The rules sought to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements.

However, due to subsequent BLM revisions and multiple legal challenges, the rules were never fully implemented, and in October 2020, the November 2016 rules were struck down by the District Court of Wyoming as the result of one such challenge.

New Mexico and California have since filed an appeal of the Wyoming Court's decision in the Tenth Circuit.

Additionally, 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 that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020.

This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016.

This agreement does not create any binding obligations for nations to limit their GHG emissions.

Nevertheless, President Biden has set ambitious targets for GHG reduction, including to achieve at least a 50 percent reduction from 2005 levels in economy-wide net GHG pollution by 2030.

Since 2012, annual reporting of GHGs has been required for persons operating certain types of industrial operations, including oil and gas production, transmission and storage operations that emit 25,000 metric tons or more of carbon dioxide equivalent per year.

EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG emission limits.

More recently, in August 2022, Congress passed the Inflation Reduction Act, which includes requirements to impose fees beginning in 2025 on methane emissions from oil and gas operations that are required to report their GHG emissions under the EPA’s GHG Reporting Rule.

EPA’s proposed rule to implement the fee requirements, “Waste Emissions Charge for Petroleum and Natural Gas Systems,” was published on January 26, 2024, with comments due by March 11, 2024.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict or impose taxes or fees on emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

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 GHGs and, in August 2022, Congress passed the IRA, which includes requirements to impose fees beginning in 2025 on certain significant sources of methane emissions from oil and natural gas operations.

While no comprehensive climate change legislation has been implemented at the federal level, the EPA, the BLM, and states or groupings of states have pursued legal initiatives in recent years that seek to reduce GHG emissions through efforts that include consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources.

See “Items 1 and 2 Business and Properties – Regulation of the Oil and Natural Gas Industry”.

While changes in U.S.

presidential administrations could increase or lessen the relative impacts of climate policies and regulations on the oil and natural gas industry, the adoption and implementation of any international, federal or state legislation or regulations that require additional reporting of GHGs or otherwise restrict or impose taxes, fees or limits on emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals.

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While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place.

Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.

If any such climatic events were to occur, they could have an adverse effect on our financial condition and results of operations and the financial condition and operations of our customers.

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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.

Restrictions on drilling or other operational activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife.

Restrictions on drilling or other operational activities intended to protect certain species of wildlife or to conserve natural resources may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife or conserve natural resources (for example, water supply).

Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed.

These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs.

Permanent restrictions imposed to protect threatened or endangered species and their habitats could prohibit drilling in certain areas or require the implementation of expensive

mitigation or conservation measures.

Permanent restrictions imposed to protect water resources or threatened or endangered species and their habitats could prohibit drilling in certain areas or require the implementation of expensive mitigation or conservation measures.

The designation or proposed designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.

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Our effective tax rate may change in the future, which could adversely impact us.

The TCJA significantly changed the U.S.

The Tax Cuts and Jobs Act of 2017 ("TCJA") significantly changed the U.S.

federal income taxation of U.S.

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corporate income tax rate, limiting interest deductions and certain deductions for executive compensation, permitting immediate expensing of certain capital expenditures, and revising the rules governing net operating losses.

The TCJA remains unclear in

some respects and continues to be subject to potential amendments and technical corrections.

The TCJA remains unclear in some respects and continues to be subject to potential amendments and technical

The United States Treasury Department and the IRS have issued significant guidance since the TCJA was enacted, interpreting the TCJA and clarifying some of the uncertainties, and are continuing to issue new guidance.

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federal income tax laws are proposed regularly and there can be no assurance that, if enacted, any such changes would not have an adverse impact on us.

For example, President Biden has suggested the reversal or modification of some portions of the TCJA and certain of these proposals, if enacted, could increase our effective tax rate.

There can be no assurance that any such proposed changes will be introduced as legislation or, if introduced, later enacted, and, if enacted, what form such enacted legislation would take.

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If the effective tax rate were to increase as a result of the future legislation, our business could be adversely affected.

Changes to regulatory agencies could pose risks related to our business operations and financial outlook.

On January 20, 2025, President Donald J.

Trump issued Executive Order No.

14158 entitled “Establishing and Implementing the President’s “Department of Government Efficiency” or “DOGE” which is tasked with making changes to eliminate regulations, cut expenditures, and restructure federal agencies, some of which could impact public companies and companies in our industry.

Through DOGE or similar recently-issued Executive Orders and initiatives, it is possible the Trump administration could institute significant changes to certain regulatory agencies.

These changes could result in a significant reduction in staff and/or federal funding, which may cause backlogs or other interruptions to regulatory reviews and approvals causing a delay to our operations and/or special projects.

As such, these changes to regulatory agencies could negatively impact our business operations and financial outlook.

Risks Related to Our Common Stock

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In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies.

Such litigation, if instituted, could result in substantial costs and diversion of management attention and resources, which could significantly harm our business, financial condition, results of operations and reputation.

Such litigation, if instituted, could result in substantial costs and

diversion of management attention and resources, which could significantly harm our business, financial condition, results of operations and reputation.

Future sales or the possibility of future sales of a substantial amount of our common stock may depress the price of shares of our common stock.

Future sales or the availability for sale of substantial amounts of our common stock in the public market, or the perception that such sales could occur, could adversely affect the prevailing market price of our common stock and could impair our ability to raise capital through future sales of equity securities.

On April 7, 2021, we filed with the SEC a “shelf” registration statement on Form S-3 that became effective on May 12, 2021.

On May 10, 2024, we filed with the SEC a “shelf” registration statement on Form S-3 that became effective on May 29, 2024.

The registration statement registers securities that may be issued by the Company in a maximum aggregate amount of up to $250,000,000, as well as up to 12,037,813 shares of common stock that may be resold by certain selling stockholders named in therein.

On September 1, 2023, we filed a prospectus supplement for the sale of up to $50,000,000 of shares of our common stock in an ATM offering under the shelf registration statement, of which approximately $0.3 million was sold under the ATM as of December 31, 2023.

Sales by the Company of common stock under the ATM or other sales by the Company of securities under a registration statement or in private placements, could be dilutive to existing shareholders.

Sales by the Company of securities under a registration statement or in private placements, could be dilutive to existing shareholders.

Additionally, sales by the Company or selling stockholders of securities, or the perception that such sales may occur, could adversely affect the trading price for our common stock.

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Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.

We are a smaller reporting company and we cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.

We are currently a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act.

As a “smaller reporting company,” we are subject to reduced disclosure obligations in our SEC filings compared to other issuers, including, among other things, being required to provide only two years of audited financial statements in annual reports and being subject to simplified executive compensation disclosures.

Until such time as we cease to be a “smaller reporting company,” such reduced disclosure in our SEC filings may make it harder for investors to analyze our operating results and financial prospects.

If some investors find our common stock less attractive as a result of any choices to reduce disclosure we may make, there may be a less active trading market for our common stock and our stock price may be more volatile.

Effective December 31, 2024, we no longer qualify as a “smaller reporting company” which will impose additional reporting requirements that may increase our costs and demands on management time.

Based on the market value of our common stock held by our non-affiliates as of June 30, 2024, we determined that we no longer qualified as a “smaller reporting company” effective December 31, 2024, and, as a result, will be unable to take advantage of certain exemptions and relief from various reporting requirements that are applicable to smaller reporting companies.

We will be required to comply with larger company disclosure obligations beginning with our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2025.

The loss of smaller reporting company status and compliance with such larger company disclosure obligations may increase our legal and financial compliance costs.

Our business and operations could be adversely affected if we lose key personnel.

We depend to a large extent on the services of our officers, including Bobby Riley, our Chief Executive Officer and President, Philip Riley, our Chief Financial Officer and Executive Vice President – Strategy , Corey Riley, our Executive Vice President – Business Intelligence, and Michael Palmer, our Executive Vice President Corporate – Land.

We depend to a large extent on the services of our officers, including Bobby Riley, our Chairman and Chief Executive Officer, Philip Riley, our Chief Financial Officer and Executive Vice President of Strategy, Corey Riley, our Chief Information and Compliance Officer, John Suter, our Chief Operating Officer, and Jeffrey Gutman, our Chief Accounting Officer.

These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies.

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• after a certain date, require the approval of the holders of at least 66 2/3% of the votes that all the stockholders would be entitled to cast to amend or repeal certain provisions of our charter or bylaws.

Our bylaws provide that the Court of Chancery of the State of Delaware will be the exclusive forum for substantially all disputes between the Company and its stockholders, which could limit stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or its directors, officers, employees or stockholders.

Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is the exclusive forum for any derivative action or proceeding brought on the Company’s behalf, any action asserting a breach of fiduciary duty owed by Company’s directors, officers, other employees or stockholders to the Company or its stockholders, any action asserting a claim against the Company arising pursuant to the Delaware General Corporation Law or as to which the Delaware General Corporation Law confers jurisdiction on the Court of Chancery of the State of Delaware, or any action asserting a claim arising pursuant to the Company’s certificate of incorporation or bylaws or governed by the internal affairs doctrine.

Our bylaws provide that the Court of Chancery of the State of Delaware will be the exclusive forum for substantially all disputes between the Company and our stockholders, which could limit stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or our directors, officers, employees or stockholders.

Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is the exclusive forum for any derivative action or proceeding brought on the Company’s behalf, any action asserting a breach of fiduciary duty owed by Company’s directors, officers, other employees or stockholders to the Company or our stockholders, any action asserting a claim against the Company arising pursuant to the Delaware General Corporation Law or as to which the Delaware General Corporation Law confers jurisdiction on the Court of Chancery of the State of Delaware, or any action asserting a claim arising pursuant to the Company’s certificate of incorporation or bylaws or governed by the internal affairs doctrine.

Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the federal district courts of the United States of America shall, to the fullest extent permitted by law, be the sole and exclusive forum for any actions arising under the Securities Act of 1933, as amended, or the Exchange Act.

These provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with the Company or its directors, officers, employees or stockholders, which may discourage such lawsuits against the Company and its directors, officers, employees or stockholders.

These provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with the Company or our directors, officers, employees or stockholders, which may discourage such lawsuits against the Company and our directors, officers, employees or stockholders.

Alternatively, if a court were to find these provisions in our bylaws to be inapplicable or unenforceable in an action, the Company may incur additional costs associated with resolving such action in other jurisdictions, which could adversely affect our business and financial condition.

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Certain of our stockholders and their respective portfolio companies may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue.

Under our certificate of incorporation, certain of our stockholders and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of

Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on the trading price of our common stock.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1A. Risk Factors