What changed in this filing

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Item 1. Business

2024-03-07 compared with 2023-03-15 · 93 added, 90 removed, 423 unchanged (30% of the section changed)

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Mid-Continent.

As of December 31, 2022, we had an interest in 1,471 gross (856 net) producing wells, approximately 992 of which we operate, and approximately 551,000 gross (365,000 net) total acres under lease.

As of December 31, 2022, we had one rig drilling.

As of December 31, 2023, we had an interest in 1,453 gross (849 net) producing wells, approximately 958 of which we operate, and 548,895 gross (364,201 net) total acres under lease.

As of December 31, 2023, we had no active drilling rigs.

Total estimated proved reserves as of December 31, 2023, were 55.7 MMBoe, all of which were proved developed.

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Our Business Strategy

The Company’s primary strategic focus is to grow the cash value and generation capability of our asset base in a safe, responsible and efficient manner, and will seek to use our net operating loss carry forwards to minimize income taxes and maximize cash flow.

The Company’s primary strategic focus is to grow the value and cash generation capability of our asset base in a safe, responsible and efficient manner, and will seek to use our net operating loss carry forwards to minimize income taxes and maximize cash flow.

We will continue to exercise financial discipline and prudent capital allocation to projects we believe provide a high rate of return in the current commodity price environment, and will remain vigilant and maintain optionality for opportunistic, value-accretive acquisitions and business combinations.

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A comparative discussion of our 2022 to 2021 operating results can be found in Item 1 “Business” included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on March 15, 2023.

Our primary operations are the development and acquisition of hydrocarbon resources.

Our primary operations are the production, development and acquisition of hydrocarbon resources.

The following table presents information concerning our operations as of December 31, 2023.

Capital Expenditures (In millions) (4)

Weighted Average Economic Reserve Life (Years)(4)

Geographic Area

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(3) Estimated proved reserves as of December 31, 2023 divided by net production for the year ended December 31, 2023.

(4) Capital expenditures for the year ended December 31, 2022, on an accrual basis and including acquisitions.

(4) Average economic reserve life using SEC prices and weighted for reserve volumes at December 31, 2023.

Mid-Continent

We held interests in approximately 551,000 gross (365,000 net) leasehold acres located primarily in Oklahoma and Kansas at December 31, 2022.

We held interests in 548,895 gross (364,201 net) leasehold acres located primarily in Oklahoma and Kansas at December 31, 2023.

Associated proved reserves at December 31, 2023 totaled 55.7 MMBoe, all of which were proved developed reserves.

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He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering.

Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers;

Meekins meets and exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers;

he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

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he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

In addition to Mr.

Allen's preparation of the reserve estimates, those estimates are further reviewed by the executive team and the Audit Committee.

To establish reasonable certainty with respect to our estimated proved reserves, the independent and internal reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.

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• ensuring compensation for the reserve engineers is not tied to the amount of reserves recorded.

Key reserve information is reviewed and approved at least annually by the Company’s Chief Executive Officer and Chief Financial Officer.

Key reserve information is reviewed quarterly and approved at least annually by the Company’s Chief Executive Officer and Chief Financial Officer.

SandRidge’s reserve engineers and the Reservoir Engineering Manager work closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates.

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In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.

The percentage of total proved reserves prepared by each of the independent petroleum consultants is shown in the

The percentage of total proved reserves prepared by the independent petroleum consultants is shown in the

Cawley, Gillespie & Associates, Inc.

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Total 95.2 % 95.0 %

The remaining 5.0% and 3.8% of estimated proved reserves as of December 31, 2022 and 2021, respectively, were based on internally prepared estimates.

The remaining 4.8% and 5.0% of estimated proved reserves as of December 31, 2023 and 2022 were based on internally prepared estimates.

A copy of the report issued by our independent reserve consultant with respect to our oil, natural gas and NGL reserves as of December 31, 2023 is filed with this report as Exhibit 99.1.

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Reserve Quantities, PV-10 and Standardized Measure

The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2022 and 2021 approximately 95% and over 96%, respectively, of which were prepared by independent reserve engineers.

The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2023 and 2022, of which approximately 95% for each year were prepared by independent reserve engineers.

See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.

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Oil (MMBbls) 7.1 8.4

NGL (MMBbls) 25.4 24.3

Natural gas (Bcf) 194.4 242.8

NGL (MMBbls) 16.2 25.4

Total proved developed (MMBoe) 55.7 74.3

Oil (MMBbls) — —

NGL (MMBbls) — —

Natural gas (Bcf) — —

NGL (MMBbls) — —

Total proved undeveloped (MMBoe) — —

Oil (MMBbls) 7.1 8.4

NGL (MMBbls) 25.4 24.3

Natural gas (Bcf) 194.4 242.8

NGL (MMBbls) 16.2 25.4

Total proved (MMBoe) 55.7 74.3

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(2) Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes.

At December 31, 2021 there was no difference between the standardized measure and PV-10 due to an excess of tax basis in oil and natural gas properties over projected undiscounted future cash flows from our proved reserves.

(3) PV-10 is a non-GAAP financial measure.

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Proved Reserves - Mid-Continent .

Proved reserves increased from 71.3 MMBoe at December 31, 2021 to 74.3 MMBoe at December 31, 2022, primarily as a result of positive revisions of 9.1 MMBoe associated with the increase in year-end SEC commodity prices for oil and natural gas, 1.8 MMBoe related to the Company's well reactivation program, and 1.0 MMBoe associated with other commercial improvements.

Further, extensions added 1.2 MMBoe and purchases added 0.2 MMBoe of proved reserves.

These increases were partially offset by 2022 production totaling 6.5 MMBoe, a decrease of 1.0 MMBoe due to higher operating expenses in the trailing twelve month period used in the projections, and a decrease of 2.8 MMBoe attributable to other revisions.

Proved reserves decreased from 74.3 MMBoe at December 31, 2022 to 55.7 MMBoe at December 31, 2023, primarily due to a decrease in year-end SEC commodity prices for oil and natural gas, price realizations and NGL yield which resulted in a decrease of 17.5 MMBoe, as well as 6.2 MMBoe from the Company's production during 2023, 1.4 MMBoe attributable to well shut-ins and other revisions, and 0.1 MMBoe in sales.

The Company also had positive revisions including purchases of 1.8 MMBoe, extensions of 1.2 MMBoe, 1.9 MMBoe associated with well positive performance revisions, and 1.7 MMBoe associated with other commercial improvements.

Proved Undeveloped Reserves.

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The following table includes information regarding our net oil, natural gas and NGL production and certain price and cost information for each of the periods indicated.

For the year ended December 31, 2021, NPB had 67 MBoe in oil production.

Year Ended December 31,

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Oil (MBbls) 1,047 949

NGL (MBbls) 1,997 2,267

Natural gas (MMcf) 20,403 21,101

NGL (MBbls) 1,705 1,997

Total volumes (MBoe) 6,152 6,463

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Oil (per Bbl) $ 74.69 $ 92.21

NGL (per Bbl) $ 31.88 $ 22.42

Natural gas (per Mcf) $ 1.71 $ 4.88

NGL (per Bbl) $ 20.83 $ 31.88

Total (per Boe) $ 24.16 $ 39.34

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Drilling Activity

During the year ended December 31, 2023 there were two operated wells drilled and four wells completed, with zero wells awaiting completion at year end 2023.

During the year ended December 31, 2022, there were eight operated wells drilled, with one third-party rig actively drilling on our operated acreage and two wells awaiting completion.

Additionally, we participated in one non-operated well drilled for the year ended December 31, 2022.

During the year ended December 31, 2021, there were no operated wells drilled.

There were no third-party rigs drilling on our operated acreage at December 31, 2021 or any wells awaiting completion and we did not participate in any non-operated wells drilled for the year ended December 31, 2021.

Additionally, we participated in one non-operated well that was drilled during the year ended December 31, 2022, and was completed during year ended December 31, 2023.

Developed and Undeveloped Acreage

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We compete with other oil and natural gas companies for leases, equipment, personnel and markets for the sale of oil, natural gas and NGLs.

We believe our leasehold acreage position, geographic concentration of operations and technical and operational capabilities enable us to compete with other oil and gas development and production companies.

However, the oil and natural gas industry is intensely competitive.

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These seasonal anomalies can pose challenges for meeting our well drilling objectives, delay the installation of production facilities, and increase competition for equipment, supplies and personnel during certain times of the year, which could lead to shortages and increase costs or delay operations.

ENVIRONMENTAL REGULATIONS

ENVIRONMENTAL, HEALTH AND SAFETY REGULATIONS

Our oil and natural gas development operations are subject to stringent and complex federal, state, tribal, regional and local laws and regulations governing, among other factors, worker safety and health, the discharge and disposal of substances into the environment, and the protection of the environment and natural resources.

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Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays or restrictions in permitting or performance of projects and the issuance of orders enjoining operations in affected areas.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment.

Any changes in or more stringent enforcement of these laws and regulations that result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements could have a material adverse effect on the Company.

For example, on January 20, 2021, the Biden Administration placed a 60-day moratorium on new oil and gas leasing and drilling permits on federal land.

In June 2021, a nationwide preliminary injunction was issued by the United States District Court in the Western District of Louisiana against the provisions of President Biden’s Executive Order 14008 that blocked oil and gas leasing operations on federal lands.

In August 2022, the U.S.

Court of Appeals for the 5th Circuit vacated and remanded the District Court’s decision for further clarification, allowing the moratorium to remain in effect.

These actions could adversely impact our business and our industry generally, particularly if the moratorium continues to be extended.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect human health or the environment.

Any issuance of new environmental laws or regulations or changes in or more stringent enforcement of existing environmental laws and regulations that result in delays or restrictions in permitting or development of projects or more stringent or costly compliance or cleanup obligations related to construction, drilling, water management, or well-completion activities or waste handling, storage, transport, remediation, disposal or discharge requirements could have a material adverse effect on the Company.

Further, we may be unable to pass on increased environmental compliance costs to our customers.

Moreover, accidental releases, including spills, may occur in the course of our operations, and there can be no assurance that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property and natural resources or personal injury.

While we do not believe that compliance with existing environmental laws and regulations and that continued compliance with existing requirements will have an adverse material effect on us, we can provide no assurance that we will not incur substantial costs in the future related to revised or additional environmental regulations that could have a material adverse effect on our business, financial condition, and results of operations.

While we do not believe that compliance with existing environmental laws and regulations and that continued compliance with existing environmental permitting requirements will have an adverse material effect on us, we can provide no assurance that we will not incur substantial costs in the future related to revised or additional environmental laws and regulations or permitting requirements that could have a material adverse effect on our business, financial condition, and results of operations.

The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on the Company.

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We currently own, lease, or operate, and in the past have owned, leased, or operated, sold or transferred properties that have been used in the exploration and production of oil and natural gas.

We believe we have utilized operating and disposal practices that were standard in the industry at the applicable time, but hazardous substances, hydrocarbons, and wastes may have been disposed or released on, from or under the properties owned, leased, or operated by us or on or under other locations where these substances and wastes have been taken for treatment or disposal.

In addition, certain of these properties have been operated by third parties whose storage, treatment and disposal or release of hazardous substances, hydrocarbons, and wastes were not under our control.

These properties and the substances or wastes disposed or released on them may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), the federal Resource Conservation and Recovery Act, (“RCRA”), and analogous state laws.

Under these laws, we could be required to investigate, monitor, remove or remediate previously disposed substances or wastes (including substances or wastes disposed of or released by prior owners or operators or third parties whose waste was commingled with ours), to investigate and clean up contaminated property, to perform corrective actions, to prevent future contamination, or to pay some or all of the costs of any such action.

CERCLA, also known as the Superfund law, and comparable state laws may impose strict, joint and several liability without regard to fault or legality of conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.

These properties and the substances or wastes that may have been generated, stored, transported, treated, disposed or released on them may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), the federal Resource Conservation and Recovery Act, (“RCRA”), and analogous state laws.

Under these laws, we could be required to investigate, monitor, remove or remediate previously disposed or released substances or wastes (including substances or wastes disposed of or released by prior owners or operators or third parties whose waste was commingled with ours), to investigate and clean up contaminated property, to perform corrective actions, to prevent future contamination, or to pay some or all of the costs of any such action.

CERCLA, also known as the Superfund law, and comparable state laws and regulations may impose strict, joint and several liability without regard to fault or legality of conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment.

These persons include current and prior owners or operators of the site where the release of a hazardous substance occurred as well as entities that disposed or arranged for the disposal of the hazardous substances released at the site.

Under CERCLA, these “potentially responsible parties” may be liable for the costs of cleaning up sites where the hazardous substances have been released into the environment, for damages to natural resources resulting from the release and for the costs of certain environmental and health studies.

Under CERCLA, these “potentially responsible parties” may be liable for the costs of investigating, cleaning up, and monitoring sites where the hazardous substances have been released into the environment, for damages to natural resources resulting from the release and for the costs of certain environmental and health studies.

Additionally, landowners and other third parties may file claims for personal injury and natural resource and property damage allegedly caused by the release of hazardous substances into the environment.

Although petroleum, natural gas and natural gas liquids are excluded from the definition of "hazardous substance" under CERCLA, despite this so-called "petroleum exclusion,” certain products used in the course of our operations may be regulated as CERCLA hazardous substances.

To date, no Company-owned or operated site has been designated as a Superfund site, and we have not been identified as a responsible party for any Superfund site.

We also generate wastes that are subject to the requirements of RCRA and comparable state statutes.

CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment from a hazardous substance release and to pursue recovery of costs incurred for those actions from “potentially responsible parties.” Although petroleum, natural gas and natural gas liquids are excluded from the definition of "hazardous substance" under CERCLA, despite this so-called "petroleum exclusion,” certain products used in the course of our operations may be regulated as CERCLA hazardous substances.

To date, no Company-owned or operated site has been designated as a Superfund site, and we have not been identified as a “potentially responsible party” at any Superfund site.

We also generate wastes that are subject to the requirements of RCRA and comparable state statutes and regulations.

RCRA imposes strict “cradle-to-grave” requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.

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Air Emissions

The federal Clean Air Act (the “CAA”), as amended, and comparable state laws and regulations restrict the emission of air pollutants through emissions standards, construction and operating permitting programs and the imposition of other compliance requirements.

These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize specific equipment or technologies to control emissions.

The federal Clean Air Act (the “CAA”), as amended, and comparable state laws and regulations restrict the emission of air pollutants through emissions standards, technology-based standards, construction and operating permitting programs and the imposition of other compliance requirements.

These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to emit or significantly increase air emissions, obtain and strictly comply with air permit requirements, or utilize specific equipment or technologies to control emissions.

For example, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry.

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For example, in October 2015, the EPA issued a final rule under the CAA, lowering the National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare.

In November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendations for designating non-attainment areas.

In November 2018, the EPA issued final rules implementing the non-attainment area designations.

While the EPA has determined that all counties in which we operate are in attainment with the 2015 ozone standard, these determinations may be revised in the future.

On December 31, 2020, EPA published its decision to retain the 2015 ozone standards;

however, the Biden Administration has announced that it intends to review this rule under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

EPA has announced that it is targeting the end of 2023 to complete its reconsideration of the 2015 ozone standards and intends to reinstall the ozone panel of the Clean Air Scientific Advisory Committee to advise the Administration.

however, in October 2021 the Biden Administration announced that was reconsidering this decision under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

On August 21, 2023, the EPA announced a new review of the ozone National Ambient Air Quality Standards , and stated that it will incorporate the ongoing reconsideration into this review.

EPA also announced that it will consider the advice and recommendation of the ozone review panel of the Clean Air Scientific Advisory Committee in its review.

Further reductions in the ozone National Ambient Air Quality Standards could affect our operations and result in the need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures.

Compliance with these and any future air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which could be significant.

In addition, on December 2, 2023, the EPA announced a final rule under the CAA to reduce methane emissions from the oil and natural gas industry.

This final rule is discussed in the Climate Change subsection below.

Compliance with this new rule, and any future air pollution control and permitting requirements, has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which could be significant.

Water Discharges

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On October 22, 2019, EPA and the Corps published a final rule repealing the 2015 WOTUS rule, and EPA and the Corps promulgated the Navigable Waters Protection Rule on April 21, 2020, which provides a revised definition of WOTUS and became effective on June 22, 2020.

These regulations have been challenged in federal court, and on August 30, 2021 the U.S.

These regulations were challenged in federal court, and on August 30, 2021 the U.S.

District Court for the District of Arizona vacated and remanded the Navigable Waters Protection Rule.

On December 7, 2021, EPA and the Corps issued a proposed rule to revise the definition of WOTUS.

A year later on December 30, 2022, the agencies announced a final rule which will take effect 60 days after publication in the Federal Register.

In the fall of 2022, the agencies announced that they intend to consider further refinements to the definition of WOTUS in a second rule that would take into account additional stakeholder engagement and implementation considerations, scientific developments, and environmental justice values.

The agencies intend to propose the second rule toward the end of 2023, with the final rule published by July 2024.

The future regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations.

On December 7, 2021, EPA and the Corps issued a proposed rule to again revise the definition of WOTUS.

A year later on December 30, 2022, the agencies announced a final rule called the “Revised Definition of “Waters of the United States’” rule which was published in the Federal Register on January 8, 2023 and took effect on March 20, 2023.

This “Revised Definition of “Waters of the United States’” rule was also challenged in federal court.

On May 25, 2023, the United States Supreme Court issued a decision in the case of Sackett v.

Environmental Protection Agency , which held that parts of the Revised Definition of “Waters of the United States’” rule are invalid.

As a result, the agencies amended key aspects of the rule to conform to the Supreme Court’s decision in Sackett .

This conforming rule called "Revised Definition of 'Waters of the United States';

Conforming," became effective on September 8, 2023.

Nevertheless, due to ongoing litigation over the January 8, 2023 Revised Definition of “Waters of the United States’” rule, the rule is not currently operative in certain states and for certain parties.

EPA and the Corps are implementing the Revised Definition of 'Waters of the United States';

Conforming," in certain states, while in others, the agencies are interpreting “WOTUS” consistent with the pre-2015 regime and the Supreme Court’s decision in Sackett until further notice.

We could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations due to these frequent changes in the regulatory definition of WOTUS and regulatory uncertainty while litigation is pending.

Moreover, any future changes to regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations.

Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works.

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As a result of these measures, the OCC from time to time has developed and implemented plans calling for wells within areas of interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents.

For example, in February 2016, the OCC issued a plan to reduce disposal well volume in the Arbuckle formation by 40 percent, covering approximately 5,281 square miles and 245 disposal wells injecting wastewater into the Arbuckle formation.

In the plan, the OCC identified 76 SandRidge-operated disposals wells, prescribed a four stage volume reduction schedule and set April 30, 2016 as the final date for compliance with the tiered volume reduction plan.

In March 2016, the OCC reduced the injection volume of additional Arbuckle disposal wells, including wells we operate.

Following earthquakes in August, September and November 2016, the OCC and the EPA further limited the disposal volumes that can be disposed in Arbuckle wells, although these actions did not cover our disposal wells.

While induced seismic events generally decreased in 2017, the OCC expanded restrictions on the use of existing Arbuckle disposal wells and imposed new reporting requirements related to disposal volumes on wells injecting produced water into the Arbuckle formation.

In February 2018, the OCC instituted a new protocol to further address seismicity in the Sooner Trend Anadarko Basin Canadian and Kingfisher County and South Central Oklahoma Oil Province Plays which requires various actions, such as a pause in operations for several hours, when certain seismic data is observed.

These and similar future protocols that may be adopted in response to future seismicity concerns may reduce the productivity of our operations in relevant areas.

Additionally, the Governor of Kansas has established the State Task Force on Induced Seismicity, composed of various administrative agencies, to study and develop an action plan for addressing seismic activity in the state.

The task force issued a recommended Seismic Action Plan calling for enhanced seismic monitoring and the development of a seismic response plan, and in November 2014, the Governor of Kansas announced a plan to enhance seismic monitoring in the state.

In March 2015, the Kansas Corporation Commission issued its Order Reducing Saltwater Injection Rates (the “Order”).

The Order identified five areas of heightened seismic concern within Harper and Sumner Counties and mandated that, within 100 days of the Order’s issuance, operators must limit saltwater injection volumes to no more than 8,000 barrels per day for any well located in one of these five areas.

SandRidge and other operators of injection wells were required to reduce the injection volume, and any injection well drilled deeper than the Arbuckle Formation was required to be plugged back to a shallower formation in a manner approved by the Kansas Corporation Commission.

In August 2016, the Kansas Corporation Commission issued an order that put a 16,000 barrels per day limit on additional Arbuckle disposal wells not previously identified in the Order.

While no additional regulatory actions have been taken in Kansas with respect to induced seismicity concerns since 2017, permit applications for new saltwater disposal well facilities have faced increased local opposition.

Similar regulatory activity has occurred in other jurisdictions in which we operate, including in Kansas by the Kansas Corporation Commission, and may occur in the future in other states and localities.

While there has not been a material impact on our ability to produce operated wells historically, changes in regulatory action or enforcement could have a material adverse impact on the wells we operate or participate in.

Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed.

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In September 2020, the EPA finalized amendments to Quad Oa that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things.

The Biden Administration announced that it intends to review the September 2020 rules under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

On June 30, 2021, Congress issued a joint resolution pursuant to the Congressional Review Act disapproving the September 2020 rule, and on November 15, 2021, EPA issued a proposed rule to revise the Quad Oa regulations that, if finalized, would require methane emissions reductions and implementation of a fugitive emissions monitoring and repair program.

On November 8, 2022, EPA issued a supplemental notice of proposed rulemaking that would impose standards for certain sources that were not addressed in the November 2021 proposal, revise the previously proposed emissions standards, and establish a “super emitter response program” allowing local regulatory agencies and EPA-certified third parties to issue notices to owners and operators of regulated facilities when they detect a so-called “super-emitting event.” The EPA is expected to finalize the rulemaking in late 2023.

It is possible that these rules and future revisions thereto will continue to require oil and gas operators to expend material sums.

The Biden Administration undertook a review of the September 2020 rules under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.

After considering comments on the November 2021 and November 2022 proposed rulemakings, on December 2, 2023, the EPA announced its final rule under the CAA to reduce methane emissions from the oil and natural gas industry.

The final rule includes several actions including finalizing revisions to the New Source Performance Standards in 40 C.F.R Part 60, Subpart OOOOb regulating GHGs (in the form of methane) and volatile organic compound emissions from new, modified and existing sources within the Crude Oil and Natural Gas source category, including sources located in the production, processing, and transmission and storage segments;

finalizing emission guidelines under 40 C.F.R.

Part 60, Subpart OOOOc for states to follow in developing and implementing state plans to establish performance standards to limit methane emissions from existing sources;

finalizing actions stemming from the joint resolution of Congress, adopted on June 30, 2021 discussed above, including creating the proposed "super emitter program”;

and finalizing a protocol under 40 C.F.R.

Part 60 for optical gas imaging.

Notably, the rule phases out and will eventually ban routine flaring of natural gas produced by newly constructed wells, and requires frequent monitoring and repair of leaks.

The Company does not currently conduct routine flaring.

This new rule and any future revisions thereto will continue to require oil and gas operators to expend material sums.

States will have two years to review and develop an implementation plan and they must set compliance dates within three years of that.

Furthermore, on January 12, 2024, EPA announced a proposed rulemaking to reduce methane emissions from the oil and gas sector pursuant to the Inflation Reduction Act.

If finalized, the rule will assess a charge on larger emitters of waste methane that exceed emissions intensity levels set by Congress in the Inflation Reduction Act.

In addition, in November 2016, the U.S.

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If finalized, the proposed rule would require various technology upgrades, impose limits related to flaring, and require LDAR plans.

The final rule is expected to be announced later this year.

The final rule was not issued in 2023 as initially expected but is expected to be announced later this year.

Notably, several states where we operated as of December 31, 2023, have already adopted rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture 95 percent of methane emissions.

We have the necessary equipment (pollution control equipment and optical gas imaging equipment for LDAR inspections) and personnel trained to assist with the inspection and reporting requirements to maintain compliance with these rules.

In addition, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

Moreover, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.

On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”).

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Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations.

It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the Paris Agreement.

Several pieces of legislation were introduced before the 117th Congress, including the Climate Emergency Act of 2021, which would have directed the President to declare a national emergency relating to climate change and ensure that the federal government invests in projects to mitigate and reduce greenhouse gas emissions.

The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves.

At the 26th Conference of the Parties to the United Nations Framework Convention of Climate Change (“COP26”) in Glasgow in November 2021, the United States and the European Union launched the Global Methane Pledge, an initiative to reduce global methane emissions by at least 30% from 2020 levels by 2030.

At COP27 in Sharm El-Sheik in November 2022, the Biden Administration unveiled an updated U.S.

Methane Emissions Reduction Action Plan, building upon the first plan released at COP26.

Most recently, at COP28, the Biden Administration announced the new technology standards pursuant to the CAA for reduced methane emissions, as discussed above in this disclosure.

It is not possible at this time to predict how or when the United States might impose further restrictions on GHGs as a result of the Paris Agreement, and the full impact of actions at COP28 remain uncertain at this time.

The future adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves.

Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities.

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The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats without first obtaining an incidental take permit and implementing mitigation measures.

Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act.

While compliance with the ESA has not had an adverse effect on our exploration, development and production operations in areas where threatened or endangered species or their habitat are known to exist, it may require us to incur increased costs to implement mitigation or protective measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons.

In addition, certain of our federal and state leases may contain stipulations that require us to take measures to safeguard certain species.

Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act (“MBTA”) and to bald and golden eagles under the Bald and Golden Eagle Protection Act (“BGEPA”).

While compliance with the ESA, MBTA and BGEPA has not had an adverse effect on our exploration, development and production operations in areas where threatened or endangered or other protected species or their habitat are known to exist, it may require us to incur increased costs to implement mitigation or protective

measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons.

In addition, certain of our federal and state leases may contain stipulations that require us to take mitigation measures to safeguard certain species.

The designation of previously unprotected species as threatened or endangered in areas where we operate 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 an adverse impact on our ability to develop and produce our reserves.

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Employee Health and Safety

Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers.

Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes and regulations, whose purpose is to protect the health and safety of workers.

In addition, the OSHA Hazard Communication Standard requires us to maintain information concerning hazardous materials used or produced in our operations and to provide this information to employees and various entities.

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The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties in excess of one million dollars per day per violation.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity.

The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we or our purchasers may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity.

Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas.

Currently, interstate pipeline companies are required to provide nondiscriminatory

transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.

Currently, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.

The FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.

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HUMAN CAPITAL

As of March 8, 2023 and December 31, 2022, we had 102 full-time employees, including 87 field employees and 15 corporate employees.

As of December 31, 2023, we had 102 full-time employees, including 87 field employees and 15 corporate employees.

We had 102 full-time employees, including 87 field employees and 15 corporate employees at December 31, 2022.

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Furthermore, we routinely evaluate our HSE processes, systems, equipment and other factors to ensure they remain aligned with our focus on risk reduction and get us closer to zero incidents.

During 2022, our experience and continuing focus on workplace safety has enabled us to preserve business continuity without sacrificing our commitment to keeping our colleagues and workplace visitors safe during the COVID-19 pandemic.

During 2023, our experience and continuing focus on workplace safety has enabled us to preserve business continuity without sacrificing our commitment to keeping our colleagues and workplace visitors safe.

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 1. Business