SANDRIDGE ENERGY INC 10-K

Item 1. Business GENERAL We are an independent oil and natural gas company, organized in 2006, with a principal focus on acquisition, development and production activities in the U.S. Mid-Continent and North Park Basin of Colorado. 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, 2020, we had an interest in 1,442 gross (837.0 net) producing wells, approximately 967 of which we operate, and approximately 666,000 gross (470,000 net) total acres under lease. As of December 31, 2020, we had no rigs drilling. Total estimated proved reserves as of December 31, 2020, were 36.9 MMBoe, of which 100% were proved developed. Our principal executive offices are located at 1 E. Sheridan Ave, Suite 500, Oklahoma City, Oklahoma 73104 and our telephone number is (405) 429-5500. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available free of charge on our website at www.sandridgeenergy.com as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. Any materials that we have filed with the SEC may be accessed via the SEC’s website address at www.sec.gov. Reorganization Under Chapter 11 and Emergence from Bankruptcy On May 16, 2016, the Debtors filed Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the reorganization plan, and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016. Pursuant to the reorganization plan, all of the Predecessor Company's common stock and other equity and debt securities were cancelled and on October 4, 2016, the Successor Company issued an aggregate of 18.9 million shares of common stock at $.001 par value and commenced trading on the New York Stock Exchange. Our Business Strategy Our business strategy in 2021 will be focused on optimizing the cash return on our assets through a continued focus on cost and capital discipline, limiting our development capital expenditures to locations that we believe will provide high rates of return in the present commodity price environment and that allow for near-term payouts. We will continue our pursuit of acquisitions and business combinations that are accretive to economic value and debt-adjusted cash flow per share, and which provide high margin properties with attractive returns at current commodity prices. We will continue to exercise financial discipline and prudent capital allocation, and we will seek to use our net operating loss carry forwards to minimize income taxes and maximize cash flow. 7 Table of Contents PRIMARY BUSINESS OPERATIONS Our primary operations are the development and acquisition of hydrocarbon resources. The following table presents information concerning our operations by geographic area as of December 31, 2020. Estimated Proved Reserves (MMBoe) (1) Daily Production (MBoe/d)(2) Reserves/ Production (Years)(3) Gross Acreage Net Acreage Capital Expenditures (In millions) (4) Area Mid-Continent 33.4 19.1 4.8 568,062 380,031 $ 6.8 North Park Basin 3.5 1.8 5.3 97,657 89,666 1.5 Total 36.9 20.9 10.1 665,719 469,697 $ 8.3 ____________________ (1) Estimated proved reserves were determined using SEC prices, and do not reflect actual prices received or current market prices. All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table below. (2) Average daily net production for the month of December 2020. (3) Estimated proved reserves as of December 31, 2020 divided by average daily net production for the month of December 2020, annualized. (4) Capital expenditures for the year ended December 31, 2020, on an accrual basis and including acquisitions. Properties Mid-Continent We held interests in approximately 568,000 gross (380,000 net) leasehold acres located in Oklahoma and Kansas at December 31, 2020. Associated proved reserves at December 31, 2020 totaled 33.4 MMBoe, 100.0% of which were proved developed reserves. Our interests in the Mid-Continent as of December 31, 2020 included 1,394 gross (789.0 net) producing wells with an average working interest of 57%. The interests are largely aggregated across the Mississippian Lime, Meramec and Osage formations. The Mississippian Lime formation is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and southern Kansas. The top of this formation is encountered between approximately 4,000 and 7,000 feet and stratigraphically between various formations of Pennsylvanian age and the Devonian-aged Woodford Shale formation. The Mississippian formation is approximately 350 to 650 feet in gross thickness across our lease position and has targeted porosity zone(s) ranging between 20 and 150 feet in thickness. The Meramec and Osage Formations are Mississippian in age, lying above the Woodford Shale and below Chester formations. The Meramec is composed of interbedded shales, sands, and carbonates while the Osage is composed of low porosity, fractured limestone and chert. The top of these target formations ranges in depth from about 5,800 feet at the northern edge of the basin to greater than 14,000 feet toward the interior of the basin. Meramec formation thickness ranges from about 50 feet to over 400 feet and the Osage formation thickness ranges from about 450 to 1,400 feet. The Woodford Shale is the primary hydrocarbon source for both the Meramec and Osage. During 2020, we did not have any drilling activity in the Mid-Continent. North Park Basin Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety. Our North Park Basin properties consisted of approximately 98,000 gross (90,000 net) acres, and 48 gross and net producing wells with a working interest of 100%, at December 31, 2020. Associated proved reserves at December 31, 2020 totaled approximately 3.5 MMBoe, of which 100% were proved developed reserves. The North Park Basin acreage is located in north central Colorado, and similar to the DJ Basin next to Colorado’s Front Range, has multiple potential pay targets in addition to the Niobrara Shale play, where our activity was focused. Although untested, zones shallower and deeper than the Niobrara have indications of potentially commercial hydrocarbons. The Niobrara Shale is characterized by stacked pay benches at depths of 5,500 to 9,000 feet with overall reservoir thickness over 450 feet. During 2020, we did not have any drilling activity in North Park Basin. 8 Table of Contents Proved Reserves The portion of a reservoir considered to contain proved reserves includes (i) the portion identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil, natural gas or NGLs on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Existing economic conditions include prices, costs, operating methods and government regulations existing at the time the reserve estimates are made. SEC prices are used to determine proved reserves, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. See further discussion of prices in “Risk Factors” included in Item 1A of this report. Preparation of Reserves Estimates Over 90% 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. 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. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers. This consultation included review of properties, assumptions and available data. Internal reserve estimates were compared to those prepared by independent reserve engineers to test the estimates and conclusions before the reserves were included in this report. The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; • the accuracy of economic assumptions; and • the judgment of the personnel preparing the estimates. Along with SandRidge’s reserve engineers the Vice President of Engineering and Reservoir serves as the primary technical professional providing oversight of our reserve estimate. The reserve engineers 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. In order to ensure the reliability of reserves estimates, SandRidge has a comprehensive SEC-compliant internal controls framework and set of policies to determine, estimate and report proved reserves including: • confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests; • ensuring the information provided by other departments within the Company such as Accounting is accurate; • communicating, collaborating, and analyzing with technical personnel; • comparing and reconciling the internally generated reserves estimates to those prepared by third parties; • utilizing experienced reservoir engineers or those under their direct supervision to prepare reserve estimates; and • ensuring compensation for the reserve engineers is not tied to the amount of reserves recorded. 9 Table of Contents 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 Vice President of Engineering and Reservoir 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. 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 table below. December 31, 2020 2019 Cawley, Gillespie & Associates, Inc. 73.6 % 50.2 % Ryder Scott Company, L.P. 17.9 % 43.0 % Total 91.5 % 93.2 % The remaining 8.5% and 6.8% of estimated proved reserves as of December 31, 2020 and 2019, respectively, were based on internally prepared estimates, primarily for the Mid-Continent area. Copies of the reports issued by our independent reserve consultants with respect to our oil, natural gas and NGL reserves as of December 31, 2020 are filed with this report as Exhibits 99.1 and 99.2. The geographic location of our estimated proved reserves prepared by each of the independent reserve consultants as of December 31, 2020 is presented below. Geographic Locations—by Area by State Cawley, Gillespie & Associates, Inc. Mid-Continent—KS, OK Ryder Scott Company, L.P. North Park Basin—CO, Mid-Continent—OK The qualifications of the technical personnel at each of these firms 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; and • Bachelor of Science Degree in Petroleum Engineering. Ryder Scott Company, L.P.: • more than 30 years of practical experience in the estimation and evaluation of petroleum reserves; • a registered professional engineer in the states of Alaska, Colorado, Texas and Wyoming; and • Bachelor of Science Degree in Petroleum Engineering and MBA in Finance. Reporting of Natural Gas Liquids NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2020, NGLs comprised approximately 30% of total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where we have contracts in place for the extraction and sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels based on a conversion rate of 42 gallons per barrel. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. The amount of NGLs extracted from produced gas can vary with individual component prices and we have limited direct control over the extent to which NGLs are extracted from our natural gas, particularly light-end components such as ethane. All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs. 10 Table of Contents 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, 2020 and 2019, over 90% 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. December 31, 2020 2019 Estimated Proved Reserves (1) Developed Oil (MMBbls) 8.5 14.1 NGL (MMBbls) 11.2 14.5 Natural gas (Bcf) 102.9 200.9 Total proved developed (MMBoe) 36.9 62.1 Undeveloped Oil (MMBbls) — 21.2 NGL (MMBbls) — 1.3 Natural gas (Bcf) — 31.5 Total proved undeveloped (MMBoe) — 27.8 Total Proved Oil (MMBbls) 8.5 35.3 NGL (MMBbls) 11.2 15.9 Natural gas (Bcf) 102.9 232.3 Total proved (MMBoe) 36.9 89.9 Standardized Measure of Discounted Net Cash Flows (in millions) (2) $ 105.0 $ 364.3 PV-10 (in millions) (3) $ 105.0 $ 364.3 ____________________ (1) Estimated proved reserves, PV-10 and Standardized Measure were determined using SEC prices, and do not reflect actual prices received or current market prices. All prices are held constant throughout the lives of the properties. 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) Oil (per Bbl) Natural gas (per Mcf) Oil (per Bbl) NGL (per Bbl) Natural gas (per Mcf) December 31, 2020 $ 39.57 $ 1.99 $ 36.54 $ 6.40 $ 0.87 December 31, 2019 $ 55.69 $ 2.58 $ 50.63 $ 12.45 $ 1.16 ____________________ (a) Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas. (b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, and regional price differentials. (2) Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes. At December 31, 2020 and 2019, the difference between the standardized measure and PV-10 was insignificant due to an excess of tax basis in oil and natural gas properties over projected undiscounted future cash flows from our proved reserves. 11 Table of Contents (3) PV-10 is a non-GAAP financial measure. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our oil and natural gas properties. 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: December 31, 2020 2019 (In millions) Standardized Measure of Discounted Net Cash Flows $ 105.0 $ 364.3 Present value of future income tax discounted at 10% — — PV-10 $ 105.0 $ 364.3 Proved Reserves - Mid-Continent . Proved reserves in the Mid-Continent, primarily the Mississippian formation, decreased from 61.4 MMBoe at December 31, 2019 to 33.4 MMBoe at December 31, 2020. This reserve reduction is due to downward revisions of 21.3 MMBoe associated with the decrease in year-end SEC commodity pricing (5.5 MMBoe from removing PUDs, and 15.8 MMBoe from remaining proved reserves), 2020 production totaling 7.8 MMBoe, and well shut-ins, sales and other revisions amounting to 8.4 MMBboe. The COVID-19 Pandemic and resulting 2020 commodity price contraction necessitated numerous operational and other cost saving initiatives. These cost saving initiatives, while value additive, sometimes resulted in changes to artificial lift, or other well performance factors that reduce forward looking projections relative to previous estimates on a subset of wells. Partially offsetting these reductions was an 8.4 MMBoe increase associated with a reduction in expenses and other commercial improvements and acquisitions of 1.1 MMBoe of proved reserves. Proved Reserves - North Park Basin. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety. Our North Park Basin proved reserves in the Niobrara decreased from 28.5 MMBoe at December 31, 2019 to 3.5 MMBoe at December 31, 2020. This reserve reduction is due primarily to downward revisions of 23.7 MMBoe associated with the decrease in year-end SEC commodity pricing (22.3 MMBoe from removing PUDs and 1.4 MMBoe from remaining proved reserves), 2020 production totaling 0.9 MMBoe and 0.6 MMBoe of negative revisions to prior estimates stemming from changes in well performance. Offsetting these reductions was a 0.2 MMBoe increase associated with a reduction in expenses and other commercial improvements. Our Niobrara proved developed reserves are attributed to 48 horizontal producing wells. Reservoir characteristics of the Niobrara in the North Park Basin are similar to those of the Niobrara in the DJ Basin, consisting of multiple stratigraphic benches. In the North Park Basin, production performance and reservoir data gathered from Niobrara producing wells confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. Proved Undeveloped Reserves. The following table summarizes activity associated with proved undeveloped reserves during the periods presented: Year Ended December 31, 2020 2019 Reserves converted from proved undeveloped to proved developed (MMBoe) — 3.7 Drilling and infrastructure capital expended to convert proved undeveloped reserves to proved developed reserves (in millions) $ — $ 95.3 There were no proved underdeveloped reserves at December 31, 2020, which was a decrease of 27.8 MMBoe from the prior year. This decrease was primarily due to the Company not having had any plans to drill any new wells in the then current commodity price environment. Total estimated proved undeveloped reserves was 27.8 MMBoe at December 31, 2019, which was a decrease of 40.1 MMBoe from the prior year. This decrease was primarily due to 39.7 MMBoe associated with removing PUDs due to the decrease in year-end SEC commodity pricing consisting of 17.8 MMBoe of Mid-Continent PUD reserves and 21.9 MMBoe of North Park Basin PUD reserves. For additional information regarding changes in proved reserves during each of the two years ended December 31, 2020 and 2019 see “Note 21—Supplemental Information on Oil and Natural Gas Producing Activities” to the accompanying consolidated financial statements in Item 8 of this report. 12 Table of Contents Significant Area Oil, natural gas and NGL production for fields containing more than 15% of our total proved reserves at each year end are presented in the table below. The Mid-Continent area contained more than 15% of total proved reserves for both years ended December 31, 2020 and 2019. Oil (MBbls) NGL (MBbls) Natural Gas (MMcf) Total (MBoe) Year Ended December 31, 2020 Mid-Continent 1,144 2,694 23,552 7,764 Year Ended December 31, 2019 Mid-Continent 1,988 2,908 33,164 10,423 Mid-Continent. The mid-continent interest are largely aggregated across the Mississippian Lime, Meramec and Osage formations. Our interests in the Mid-Continent area as of December 31, 2020 included 1,394 gross (789.0 net) producing wells and a 57% average working interest in the producing area. 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. Year Ended December 31, 2020 2019 Production data (in thousands) Oil (MBbls) 2,084 3,519 NGL (MBbls) 2,694 2,910 Natural gas (MMcf) 23,552 33,164 Total volumes (MBoe) 8,703 11,956 Average daily total volumes (MBoe/d) 23.8 32.8 Average prices—as reported (1) Oil (per Bbl) $ 35.33 $ 52.96 NGL (per Bbl) $ 6.67 $ 12.23 Natural gas (per Mcf) $ 0.97 $ 1.33 Total (per Boe) $ 13.15 $ 22.26 Expenses per Boe Production costs (2) $ 4.99 $ 7.60 __________________ (1) Prices represent actual average prices for the periods presented and do not include effects of derivative transactions. (2) Represents production costs per Boe excluding production and ad valorem taxes. 13 Table of Contents Productive Wells The following table presents the number of productive wells in which we owned a working interest at December 31, 2020. We operate substantially all of our wells. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. 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 Gross Net Gross Net Gross Net Area Mid-Continent 1,060 591 334 198 1,394 789 North Park Basin 48 48 — — 48 48 Total 1,108 639 334 198 1,442 837 Drilling Activity The following table presents information with respect to wells completed during the periods indicated. This information is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. During the year ended December 31, 2020, there were no wells drilled or completed. 2019 Gross Net Completed Wells Development Productive 28 20.6 Dry — — Total 28 20.6 Exploratory Productive — — Dry — — Total — — Total Productive 28 20.6 Dry — — Total 28 20.6 We had no third-party rigs operating on our Mid-Continent or North Park Basin acreage at December 31, 2020 or any wells awaiting completion. Developed and Undeveloped Acreage The following table presents information regarding our developed and undeveloped acreage at December 31, 2020. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety. Developed Acreage Undeveloped Acreage Gross Net Gross Net Area Mid-Continent 492,965 346,098 75,097 33,933 North Park Basin 18,676 18,443 78,981 71,223 Total 511,641 364,541 154,078 105,156 14 Table of Contents Approximately 0.94% of our gross total acreage in the Mid-Continent and 44.55% in North Park Basin is on federal lands. Many 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 establish production from the leasehold acreage prior to expiration, which will keep the lease from expiring until production has ceased. As of December 31, 2020, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows: Acres Expiring Gross Net Twelve Months Ending December 31, 2021 4,280 2,638 December 31, 2022 3,181 2,370 December 31, 2023 — — December 31, 2024 and later 566 339 Other (1) 146,051 99,809 Total 154,078 105,156 ____________________ (1) Leases remaining in effect until development efforts or production on the particular lease has ceased. The acreage due to expire during the twelve months ending December 31, 2021, includes approximately 2,717 gross (1,271 net) acres in the Mid-Continent and 1,564 gross (1,367 net) acres in the North Park Basin. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety. Marketing and Customers We sell our oil, natural gas and NGLs to a variety of customers, including utilities, oil and natural gas companies and trading and energy marketing companies. We had three customers that each individually accounted for more than 10% of our total revenue during the 2020 period. 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. The number of readily available purchasers in the areas where we sell our production makes it unlikely that the loss of a single customer would materially affect our sales. We do not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements. Title to Properties As is customary in the oil and natural gas industry, we conduct a preliminary review of the title to our properties. Prior to commencing drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects, typically at our expense. In addition, prior to completing an acquisition of producing oil and natural gas assets, we perform title reviews on the most significant leases and depending on the materiality of properties, may obtain a drilling title opinion or review previously obtained title opinions. 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. COMPETITION 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 exploration and production operations. However, the oil and natural gas industry is intensely competitive. See “Item 1A. 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. Changes in the availability or price of oil, natural gas and NGLs or other forms of 15 Table of Contents 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. SEASONAL NATURE OF BUSINESS Generally, demand for natural gas decreases during the summer months and increases during the winter months and demand for oil peaks during the summer months. Certain natural gas purchasers utilize natural gas storage facilities and acquire some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. 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 General 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. Numerous governmental entities, including the EPA and analogous state and local agencies, (and, under certain laws, private individuals) have the power to enforce compliance with these laws and regulations and any permits issued under them. These laws and regulations may, among other things: (i) require permits to conduct exploration, drilling, water withdrawal, wastewater disposal and other production related activities; (ii) govern the types, quantities and concentrations of substances that may be disposed or released into the environment or injected into formations in connection with drilling or production activities, and the manner of any such disposal, release, or injection; (iii) limit or prohibit construction or drilling activities or require formal mitigation measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; (iv) require investigatory and remedial actions to mitigate pollution conditions arising from the Company’s operations or attributable to former operations; (v) impose safety and health restrictions designed to protect employees and others from exposure to hazardous or dangerous substances; and (vi) impose obligations to reclaim and abandon well sites and pits. 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, and on January 27, 2021, the Department of Interior acting pursuant to an Executive Order from President Biden suspended the federal oil and gas leasing program indefinitely. These actions could have a material adverse effect on the Company and our industry. Prior to the North Park Basin sale, approximately 7.34% of our gross total acreage was on federal lands and post sale approximately 0.94% of our gross total acreage was on federal lands. 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. 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. 16 Table of Contents Hazardous Substances and Wastes We currently own, lease, or operate, and in the past have owned, leased, or operated, 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 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. 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. 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 steps to recover costs incurred for those actions from 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 responsible party for any Superfund site. We also generate wastes that are subject to the requirements of RCRA and comparable state statutes. RCRA imposes strict “cradle-to-grave” requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced waters and other wastes associated with the exploration, production and/or development of oil and natural gas, including naturally-occurring radioactive material, if properly handled, are currently excluded from regulation as hazardous wastes under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste requirements. However, it is possible that these wastes could be classified as hazardous wastes in the future. Any change in the exclusion for such wastes could potentially result in an increase in costs to manage and dispose of wastes which could have a material adverse effect on our results of operations and financial position. 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. 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. This rule could cause small facilities to be aggregated for permitting purposes, resulting in treatment as a major source, and thereby triggering more stringent air permitting requirements. The need to acquire such permits has the potential to delay or limit the development of our oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. 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. The EPA was required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017, but missed the deadline. Subsequently, 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 2018, the EPA issued final rules implementing the non-attainment area designations. While the EPA has determined 17 Table of Contents that all counties in which we operate are in attainment with the new 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 . 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 The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act (the “CWA”), and analogous state laws and implementing regulations, impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States. Pursuant to these laws and regulations, the discharge of pollutants into regulated waters is prohibited unless it is permitted by the EPA, the Army Corps of Engineers (“Corps”) or an analogous state or tribal agency. We do not presently discharge pollutants associated with the exploration, development and production of oil and natural gas into federal or state waters. The CWA and analogous state laws and regulations also impose restrictions and controls regarding the discharge of sediment via storm water run-off from a wide variety of construction activities. Such activities are generally prohibited from discharging sediment unless permitted by the EPA or an analogous state agency. The scope of EPA’s and the Corps’ regulatory authority under Section 404 of the CWA has been the subject of extensive litigation and frequently changing regulations. The EPA issued a final rule in September 2015 that attempted to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”) under Section 404 of the CWA. The EPA and the Corps then proposed a rulemaking in June 2017 to repeal the June 2015 WOTUS rule and also announced their intent to issue a new rule redefining the term WOTUS as used in the CWA. The EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 WOTUS rule for two years. 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, however, and the scope of the CWA’s jurisdiction may remain fluid until all litigation is concluded. Further regulatory changes are likely, as the Biden Administration has announced that it intends to review the Navigable Waters Protection Rule under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis . The pending litigation and 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. 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. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs. Finally, the Oil Pollution Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and/or the CWA include inspection and maintenance programs to minimize spills from oil storage and conveyance systems; the use of secondary containment systems to prevent spills from reaching nearby water bodies; proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill; and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. We have developed and implemented SPCC plans for properties as required under the CWA. Subsurface Injections Underground injection operations performed by us are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although the Company monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property damages and personal 18 Table of Contents injuries. 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. If such laws are adopted in areas where we conduct operations, our operating costs may increase significantly. Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has issued rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. 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. 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. The adoption of any new laws, regulations, or directives that restrict our ability to dispose of saltwater generated by production and development activities , whether by plugging back the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or otherwise, or by requiring us to shut down disposal wells, could significantly increase our costs to manage and dispose of this saltwater, which could negatively affect the economic lives of the affected properties. In addition, we could find ourselves subject to third party lawsuits alleging damages resulting from seismic events that occur in our areas of operation. Climate Change 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 19 Table of Contents 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. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing. In June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of a leak detection and repair (“LDAR”) program to minimize methane emissions, under the CAA’s New Source Performance Standards in 40 C.F.R. Part 60, Subpart OOOOa (“Quad Oa”). On April 18, 2017, the EPA announced its intention to reconsider certain aspects of those regulations, and in June 2017, the EPA proposed a two-year stay of certain requirements of the Quad Oa regulations. In October 2018, the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify that meeting certain Quad Oa requirements is technically infeasible. The EPA proposed further revisions to Quad Oa on September 24, 2019, including rescinding the methane requirements in Quad Oa that apply to sources in the production and processing segments of the industry. 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 has 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 , which review may result in the reinstatement of the now-rescinded standards or promulgation of more stringent standards. Regardless of the September 2020 amendments to Quad Oa, it is possible that these rules and future revisions thereto will continue to require oil and gas operators to expend material sums. In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the EPA Quad Oa requirements. However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. Further, in September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018. Both the 2016 and the 2018 rule were challenged in federal court. On July 21, 2020, a Wyoming federal court vacated almost all of the 2016 rule, including all provisions relating to the loss of gas through venting, flaring, and leaks, and on July 15, 2020, a California federal court vacated the 2018 rule. 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, 2020, including Colorado, 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. Compliance with these rules could require us to purchase pollution control equipment and optical gas imaging equipment for LDAR inspections, and to hire additional personnel to assist with inspection and reporting requirements. 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. 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”). However, the Paris Agreement does not impose any binding obligations on the United States. In June 2017, President Trump announced that the United States would withdraw from the Paris Agreement, which became effective November 4, 2020. President Joe Biden announced that the United States will rejoin the Paris Agreement as of January 20, 2021. 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. 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 20 Table of Contents 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. 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. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation. Endangered or Threatened Species 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, including the sage grouse, and their habitats known to be located within the area of the lease. Although the U.S. Fish and Wildlife Service (“USFWS”) declined to list the sage grouse under the ESA in 2015 and subsequently developed a conservation plan to protect existing habitat, some environmental groups have continued to raise concerns about sufficient protections for the sage grouse population. Under the plan, the USFWS committed to review the status of the species every five years to evaluate conservation actions, although USFWS has not yet completed the five-year review that was due to be completed in 2020. In addition, the U.S. Department of Interior (“DOI”) proposed in December 2018 revisions to the existing sage grouse conservation plan that, amongst other things, was intended to give the DOI and individual states flexibility to allow for increased activity in grouse habitat management areas encompassing parts of Colorado, Idaho, Nevada, Northern California, Oregon, Utah and Wyoming. Several conservation groups challenged the rules, and on October 16, 2019, the U.S. District Court for the District of Idaho issued a preliminary injunction blocking implementation of the new rules in Idaho, Wyoming, Colorado, Utah, Nevada, Oregon, and part of California. In January 2021, the DOI issued Records of Decision for six Supplemental Environmental Impact Statements for management of sage grouse habitat on public lands in seven states to address the court’s decision; however, the Biden Administration has announced that it intends to review these acts under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis . It is also possible that this review could result in the sage grouse being re-listed under the ESA in the future. If endangered or otherwise protected species are located in areas where we wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. 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 . 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. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. 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. 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. Pursuant to the Federal 21 Table of Contents Emergency Planning and Community Right-to-Know Act, facilities that store threshold amounts of chemicals that are subject to OSHA’s Hazard Communication Standard must submit information regarding those chemicals by March 1 of each year to state and local authorities in order to facilitate emergency planning and response. That information is generally available to employees, state and local governmental authorities, and the public. We do not believe that compliance with applicable laws and regulations relating to worker health and safety will have a material adverse effect on our business and results of operations. State and Other Regulation The states in which we operate, along with some municipalities and Native American tribal areas, regulate some or all of the following activities: 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. 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. Hydraulic Fracturing Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Oil and natural gas may be recovered from certain of our oil and natural gas properties through the use of hydraulic fracturing, combined with sophisticated drilling. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted federal regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued the Quad Oa regulations for the oil and natural gas industry under the CAA, as described above; and in June 2016 issued final effluent limitations guidelines under the CWA that waste water from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant. The EPA also issued an Advance Notice of Proposed Rulemaking under the Toxic Substances Control Act (“TSCA”) in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing but, to date, has taken no further action. 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. The June 2016 decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit. However, following issuance of a presidential executive order to review rules related to the energy industry, in July 2017, the BLM published a proposed rule to rescind the 2015 final rule. In September 2017, the Tenth Circuit issued a ruling to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in light of the BLM’s proposed rulemaking. 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 . 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. At the state level, some states, including Oklahoma, Kansas and Colorado, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure, operational or well construction requirements on hydraulic fracturing activities, or that prohibit hydraulic fracturing altogether. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions, and associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable, and could cause us to incur substantial compliance costs. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce in commercial quantities. 22 Table of Contents 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. 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: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. 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. There have not been any incidents, citations or suits related to our hydraulic fracturing activities involving material environmental concerns. OTHER REGULATION OF THE OIL AND NATURAL GAS INDUSTRY The oil and natural gas industry is extensively regulated by numerous federal, state, local, and regional authorities, as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases the Company’s cost of doing business and, consequently, affects its profitability, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production. The price of oil, natural gas and NGLs is not currently regulated and are made at market prices. Although oil, natural gas and NGL prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil, natural gas and NGL prices might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Drilling and Production Our operations are subject to various types of regulation at federal, state, local and Native American tribal levels that include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribal areas where we operate regulate one or more of the following activities: • the location of wells; • the method of drilling and casing wells; • the timing of construction or drilling activities; • the rates of production, or “allowables”; • the use of surface or subsurface waters; • the surface use and restoration of properties upon which wells are drilled; • the plugging and abandoning of wells; and • the notice to surface owners and other third parties. State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties 23 Table of Contents and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. 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. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Natural Gas Sales and Transportation The availability, terms and cost of transportation significantly affect sales of oil and natural gas. 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. 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. 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. 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. 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. 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. 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. 24 Table of Contents Oil and NGL Sales and Transportation Rates Sales prices of oil and NGLs are not currently regulated and are made at market prices. Our sales of these commodities are, however, subject to laws and to regulations issued by the Federal Trade Commission (the “FTC”) prohibiting manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these regulations, including the ability to assess civil penalties in excess of one million dollars per day per violation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Some of our transportation of oil, natural gas and NGLs is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC’s regulation of crude oil and natural gas liquids transportation rates may tend to increase the cost of transporting crude oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. 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. EMPLOYEES As of March 1, 2021, we had 103 full-time employees, including 87 field employees and 16 corporate employees. As of December 31, 2020, we had 114 full-time employees, including 98 field employees and 16 corporate employees. At December 31, 2019, we had 270 full-time employees, including 140 field employees and 130 corporate employees. Health, Safety and Environment Our people are a key driver to our success in Health, Safety and Environment ("HSE"). 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. As part of our HSE policy, we aim to identify and correct any work practices that pose an HSE risk to our employees. The Company is devoted to creating a sustainable environment and implementing process improvements for both health and safety and the environment. We evaluate our processes to ensure our protection schemes and work practices minimize these risks. Furthermore, we periodically evaluate our HSE objectives to ensure they remain aligned with our HSE goals and annually create a strategy focused on risk reduction to get us closer to zero incidents. During 2020, our experience and continuing focus on workplace safety have enabled us to preserve business continuity without sacrificing our commitment to keeping our colleagues and workplace visitors safe during the COVID-19 pandemic. 25 Table of Contents