What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2023-03-15 compared with 2022-03-10 · 99 added, 110 removed, 414 unchanged (34% of the section changed)

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Mid-Continent.

Prior to February 5, 2021, we held assets in the North Park Basin of Colorado, which have been sold in their entirety.

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, 2021, we had no rigs drilling.

Total estimated proved reserves as of December 31, 2021, were 71.3 MMBoe, of which 100% were proved developed.

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

Total estimated proved reserves as of December 31, 2022, were 74.3 MMBoe, all of which were proved developed.

Our principal executive offices are located at 1 E.

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The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown on page 10 below.

(2) Average daily net production for the month of December 2021.

(3) Estimated proved reserves as of December 31, 2021 divided by average daily net production for the month of December 2021, annualized.

(2) Average daily net production for the year ended December 31, 2022.

(3) Estimated proved reserves as of December 31, 2022 divided by net production for the year ended December 31, 2022.

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

Mid-Continent

We held interests in approximately 551,000 gross (368,000 net) leasehold acres located in Oklahoma and Kansas at December 31, 2021.

Associated proved reserves at December 31, 2021 totaled 71.3 MMBoe, 100.0% of which were proved developed reserves.

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

Associated proved reserves at December 31, 2022 totaled 74.3 MMBoe, all of which were proved developed reserves.

Our interests in the Mid-Continent as of December 31, 2022 included 1,471 gross (856 net) producing wells with an average working interest of 58.2%.

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The Woodford Shale is the primary hydrocarbon source for both the Meramec and Osage.

During 2021, we did not have any drilling activity.

North Park Basin

On February 5, 2021, we sold all of our oil and natural gas properties and related assets of the North Park Basin ("NPB") in Colorado for a purchase price of $47 million in cash.

Net proceeds were $39.7 million in cash as a result of customary effective date adjustments and a $0.8 million post-close adjustment made during the second half of the year.

The sale resulted in a $18.9 million gain after the post-close adjustment.

Proved Reserves

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Preparation of Reserves Estimates

Over 96% of the proved oil, natural gas and NGL reserves disclosed in this report are based on reserve estimates determined and prepared by independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells.

A small portion of the proved reserves disclosed in this report were determined by internal reserve engineers.

Approximately 95 percent of the proved oil, natural gas and NGL reserves disclosed in this report have been independently prepared by Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions.

CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.

Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 18, 2023, filed as an exhibit to this Annual Report on Form 10-K, was Mr.

Zane Meekins.

Meekins has been a practicing consulting petroleum engineer at CGA since 1989.

Meekins is a Registered Professional Engineer in the State of Texas (License No.

71055) and has over 35 years of practical experience in petroleum engineering, with over 33 years of experience in the estimation and evaluation of reserves.

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;

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.

The primary technical person responsible for preparing the reserve estimates within the Company is Mr.

Eric Allen, the Reservoir Engineering Manager.

Allen graduated from Oklahoma State University with a Bachelor of Science in Chemical Engineering in 2010 and has been practicing petroleum engineering since graduating.

Allen graduated from the University of Oklahoma with a Master’s in Business Administration.

Allen has over 13 years of practical experience in petroleum engineering with 8 of those years having been spent in the estimation and evaluation of reserves.

Since 2016, Mr.

Allen has been a Registered Professional Engineer in the State of Oklahoma (License No.

29209) and is an active member of 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.

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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• the judgment of the personnel preparing the estimates.

The Reservoir Engineering Supervisor serves as the primary technical professional providing oversight of our reserve estimate.

The reserve engineers and third party engineering consultants monitor well performance and make reserve estimate adjustments as necessary to ensure the most current information is reflected.

The Reservoir Engineering Manager serves as the primary technical professional providing oversight of our reserve estimate.

CGA and the Reservoir Engineering Manager monitor well performance and make reserve estimate adjustments as necessary to ensure the most current information is reflected.

We encourage ongoing professional education for our engineers and analysts on new technologies and industry advancements as well as refresher training on basic skill sets.

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

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

These independently developed reserves estimates are presented to the audit committee.

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.

These independently developed reserve estimates are presented to the Audit Committee of the Board of Directors ("Audit Committee").

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.

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95.0 % 96.2 %

Ryder Scott Company, L.P.

(1) — % 17.9 %

Total 95.0 % 96.2 %

(1) Subsequent to the sale of NPB properties, Ryder Scott no longer provides engineering services on reserves.

The remaining 3.8% and 8.5% of estimated proved reserves as of December 31, 2021 and 2020, respectively, were based on internally prepared estimates, primarily for the Mid-Continent area.

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.

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, 2022 is filed with this report as Exhibit 99.1.

Cawley, Gillespie & Associates prepared reserves for our Mid-Continent properties located in Kansas and Oklahoma as of December 31, 2022.

The qualifications of the technical personnel at Cawley, Gillespie & Associates, Inc.

primarily responsible for overseeing the firm’s preparation of the Company’s reserves estimates included in this report are set forth below.

These qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

Cawley, Gillespie & Associates, Inc.:

• more than 25 years of practical experience in the estimation and evaluation of petroleum reserves;

• a registered professional engineer in the state of Texas;

• Bachelor of Science Degree in Petroleum Engineering.

Reporting of Natural Gas Liquids

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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 reserve reports were based on our drilling schedule at the time year-end reserve estimates were prepared.

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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All prices are held constant throughout the lives of the properties.

For 2021, the estimated proved reserves include Mid-Continent only.

For 2020, the estimated proved reserves include Mid-Continent and NPB.

The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table below:

Index prices (a) Weighted average

wellhead prices (b) (c)

wellhead prices (b)

(per Bbl) Natural gas

(per Mcf) Oil

(per MMBtu) Oil

(per Bbl) Natural gas

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(b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, regional price differentials and excludes any impact of derivatives.

For 2020, the estimated proved reserves include Mid-Continent and NPB.

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

At December 31, 2021 and 2020 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.

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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PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities.

It is useful because its calculation is not dependent on the taxpaying status of the entity.

The following table provides a reconciliation of our Standardized Measure to PV-10:

(In millions)

Standardized Measure of Discounted Net Cash Flows $ 432.9 $ 105.0

Present value of future income tax discounted at 10% — —

The following table provides a reconciliation of our PV-10 to Standardized Measure:

(In thousands)

PV-10 $ 810,663 $ 432,914

Present value of future income tax discounted at 10% $ (3,798) $ —

Standardized Measure of Discounted Net Cash Flows $ 806,865 $ 432,914

Proved Reserves - Mid-Continent .

Proved reserves increased from 33.4 MMBoe at December 31, 2020 to 71.3 MMBoe at December 31, 2021, primarily as a result of positive revisions of 27.3 MMBoe associated with the increase in year-end SEC commodity prices for oil and natural gas, 13.6 MMBoe associated with reduction in expenses and other commercial improvements, 3.7 MMBoe related to a well reactivation program, and purchases of 1.4 MMBoe of proved reserves.

The Company also recorded 2021 production totaling 6.7 MMBoe and a decrease of 1.4 MMBoe attributable to well shut-ins, sales and other revisions.

Proved Reserves - North Park Basin.

Proved reserves in the North Park Basin decreased from 3.5 MMBoe at December 31, 2020 to 0 MMBoe at December 31, 2021, as the result of the sale of 3.4 MMBoe of proved reserves and 2021 production totaling 0.1 MMBoe.

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 Undeveloped Reserves.

There were no proved undeveloped reserves at December 31, 2022 and 2021.

For additional information regarding changes in proved reserves during each of the two years ended December 31, 2021 and 2020 see “Note 21—Supplemental Information on Oil and Natural Gas Producing Activities” to the accompanying consolidated financial statements in Item 8 of this report.

For additional information regarding changes in proved reserves during each of the three years ended December 31, 2022, 2021 and 2020 see “Note 20—Supplemental Information on Oil and Natural Gas Producing Activities” to the accompanying consolidated financial statements in Item 8 of this report.

Production and Price History

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 years ended December 31, 2021 and 2020, NPB had 67 MBoe and 940 MBoe of oil production, respectively.

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

Year Ended December 31,

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The following table presents the number of productive wells in which we owned a working interest at December 31, 2022.

We operate substantially all of our net wells.

We operate the majority of all wells in which we owned a working interest at December 31, 2022 and 2021.

Productive wells consist of wells that are currently producing hydrocarbons.

Gross wells are the total number of producing wells in which we have a working interest and net wells are the sum of the fractional working interests owned in gross wells.

Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.

Oil Natural Gas Total

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Drilling Activity

During the years ended December 31, 2021 and 2020, 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.

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.

Developed and Undeveloped Acreage

The following table presents information regarding our developed and undeveloped acreage at December 31, 2022.

Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.

Developed Acreage Undeveloped Acreage

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Less than 5% of the leases included in the undeveloped acreage above will expire at the end of their respective primary terms.

To prevent expiration, we may exercise our contractual rights to extend the terms of leases we value or may

establish production from the leasehold acreage prior to expiration, which would keep the lease from expiring until production has ceased.

To prevent expiration, we may exercise our contractual rights to extend the terms of leases we value or may establish production from the leasehold acreage prior to expiration, which would keep the lease from expiring until production has ceased.

As of December 31, 2022, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows:

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December 31, 2026 and later 566 305

Other (1) 82,897 27,841

Total (1) 1,361 774

____________________

(1) Leases remaining in effect until development efforts or production on the particular lease has ceased.

Marketing and Customers

(1) The Company has 61,835 gross (26,237 net) undeveloped acres not subject to expiration.

We sell our oil, natural gas and NGLs to a variety of customers, including oil and natural gas companies and trading and energy marketing companies.

We had two customers that each individually accounted for more than 10% of our total revenue during the 2021 period.

We had two purchasers that each individually accounted for more than 10% of our total revenue during the year ended December 31, 2022.

See “Note 1—Summary of Significant Accounting Policies” to the accompanying consolidated financial statements in Item 8 of this report for additional information on our major customers.

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To date, we have obtained drilling title opinions on substantially all of our producing properties and believe that we have good and defensible title to our producing properties.

Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe does not materially interfere with the use of, or affect the carrying value of the properties.

Our oil and natural gas properties are subject to customary royalty and other interests, and liens for current taxes and other burdens, which we believe does not materially interfere with the use of, or affect the carrying value of the properties.

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 development and production operations.

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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Risk Factors” for additional discussion of competition in the oil and natural gas industry.

Oil, natural gas and NGLs compete with other forms of energy available to customers, including alternate forms of energy such as electricity, coal and fuel oils.

Oil, natural gas and NGLs compete with other forms of energy available to customers, including alternate forms of energy such as wind, solar, and nuclear generated electricity, coal and biofuels.

Changes in the availability or price of oil, natural gas and NGLs or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil, natural gas and NGLs.

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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.

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

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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 recommendation for designating non-attainment areas.

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;

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 intends to issue a proposed rule reconsidering its decision to retain the 2015 ozone standard by fall 2022 and a final rule by the end of 2023.

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.

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 costs could be significant.

Water Discharges

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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, which is expected to be finalized in late 2022 or early 2023.

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.

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Some states have considered laws mandating flowback and produced water recycling.

Other states have undertaken

studies, in some cases such as New Mexico in conjunction with the EPA, to assess the feasibility of recycling produced water on a large scale.

Other states have undertaken studies, in some cases such as New Mexico in conjunction with the EPA, to assess the feasibility of recycling produced water on a large scale.

If such laws are adopted in areas where we conduct operations, our operating costs may increase significantly.

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In December 2009, the EPA published its findings that emissions of CO 2 , methane and certain other “greenhouse gases” ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of

Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.

Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds.

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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.

EPA has also announced its intention to issue a supplemental proposal in 2022 that may expand on or modify the 2021 proposal in response to public input.

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.

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As a result of these decisions, the 1979 regulations concerning venting, flaring and lost production on federal land have been reinstated.

The Biden Administration is likely to impose new regulations on GHG emissions from oil and natural gas production operations on federal land, given the long-term trend towards increasing regulation in this area.

Moreover, several states where we operated as of December 31, 2021, have already adopted rules requiring operators of both new and existing sources to develop and implement a 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 inspection and reporting requirements to maintain compliance with these rules.

On November 28, 2022, the BLM announced a new proposed rule regulating emissions of methane in connection with the production of oil and gas on federal and Tribal lands.

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.

Notably, several states where we operated as of December 31, 2022, 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.

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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.

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.

Ultimately, this could make it more difficult to secure

funding for exploration and production activities or increase the costs of such funding.

Ultimately, this could make it more difficult to secure funding for exploration and production activities or increase the costs of such funding.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time.

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

Further, in February 2016, the USFWS published a final policy which alters how it identifies critical habitats for endangered and threatened species.

In August 2019, the USFWS issued three final rules revising its ESA regulations, consisting of changes to the procedures and criteria for listing or delisting species and designating critical habitat, removal of the automatic take prohibition for species listed as threatened, and regulations for protection of threatened species, and new procedures and time frames for required consultations by other federal agencies.

The USFWS also issued a final rule in December 2020 defining the term “habitat” for purposes of making critical habitat designations under the ESA.

In general, these rules were designed to alleviate some of the burdens of the ESA and streamline its implementation, but the prospect of new species listings and critical habitat designations remains.

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

On October 27, 2021, the USFWS issued a proposal to rescind the December 2020 ruling, and the USFWS may finalize the rescission of the rule in 2022.

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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the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas.

These regulations may affect the number and location of our wells and the amounts of oil and natural gas that

may be produced from our wells, and increase the costs of our operations.

These regulations may affect the number and location of our wells and the amounts of oil and natural gas that may be produced from our wells, and increase the costs of our operations.

Moreover, obtaining or renewing permits and other approvals for operating on Native American lands can take substantial amounts of time, and could result in increased costs or delays to our operations.

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Separately, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands.

However, the U.S.

District Court of Wyoming struck down this rule in June 2016.

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The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017.

The Biden Administration has announced that it intends to review the repeal of the 2015 hydraulic fracturing rule under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis , but the BLM has not yet taken further regulatory action on this topic.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain.

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In addition to asserting regulatory authority, certain government agencies have conducted reviews focusing on environmental issues associated with hydraulic fracturing practices.

For example, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources in December 2016.

For example, the EPA released its final report, Hydraulic Fracturing for Oil and Gas:

Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States , regarding the potential impacts of hydraulic fracturing on drinking water resources in December 2016.

The EPA report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water sources “under some circumstances,” noting that the following 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:

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We diligently review best practices and industry standards and comply with all regulatory requirements in the protection of potable water sources.

Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time and disposing of all non-commercially produced fluids in certified disposal wells at

depths below the potable water sources.

We are not aware of any incidents, citations or suits related to our hydraulic fracturing activities involving material environmental concerns.

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Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdiction.

State agencies in Colorado, Kansas and Oklahoma impose financial assurance requirements on operators.

State agencies in Kansas and Oklahoma impose financial assurance requirements on operators.

The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

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The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”).

Federal and state regulations govern the price and terms for access to oil and natural gas pipeline

transportation.

Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation.

The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production.

FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act of 1978.

The FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act of 1978.

Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production.

Under the Energy Policy Act of 2005 (the “EPAct 2005”), FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties in excess of one million dollars per day for each violation and disgorgement of profits associated with any violation.

While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.

In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation.

Under the Energy Policy Act of 2005 (the “EPAct 2005”), the FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties in excess of one million dollars per day for each violation and disgorgement of profits associated with any violation.

While our systems have not been regulated by the FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices.

In addition, Congress may enact legislation or the FERC may adopt regulations that may subject certain of our otherwise non-the FERC jurisdictional facilities to further regulation.

Failure to comply with those regulations in the future could subject us to civil penalty liability.

The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas.

With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that we undertake, we are thus required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC.

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

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.

Commencing in 1985, 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.

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.

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.

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.

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.

However, the natural gas industry historically has been very heavily regulated;

therefore, the less stringent regulatory approach currently pursued by FERC and Congress might not continue indefinitely into the future.

therefore, the less stringent regulatory approach currently pursued by the FERC and Congress might not continue indefinitely into the future.

The Company is unable to determine what effect, if any, future regulatory changes might have on the Company’s natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive.

Under the FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters.

Although its policy is still in flux, in the past FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our cost of transporting gas to point-of-sale locations.

Although its policy is still in flux, in the past the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our cost of transporting gas to point-of-sale locations.

Oil and NGL Sales and Transportation Rates

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Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry.

We are not able at

this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations.

We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations.

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.

At December 31, 2020, we had 114 full-time employees, including 98 field employees and 16 corporate employees.

We had 101 full-time employees, including 85 field employees and 16 corporate employees at December 31, 2021.

Health, Safety and Environment

Our people are a key driver to our success in Health, Safety and Environment ("HSE").

Our people are a key driver to our success in Health, Safety and Environment ("HSE") related outcomes.

Our HSE policy includes a commitment to provide safe and healthy working conditions for the prevention of work-related injury and ill health and is appropriate for the purpose, size and context of the organization.

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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