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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to            
Commission File Number: 001-33784
SANDRIDGE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware20-8084793
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
1 E. Sheridan Ave, Suite 500
Oklahoma City, Oklahoma
73104
(Address of principal executive offices)(Zip Code)
(405429-5500
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading SymbolName of each exchange on which registered
Common Stock, $0.001 par valueSDNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes ☐ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7276(b)) by the registered public accounting firm that prepared or issued its audit report.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes No ☑

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes No ☐



The aggregate market value of our common stock held by non-affiliates on June 30, 2021 was approximately $195.5 million based on the closing price as quoted on the New York Stock Exchange. As of March 3, 2022, there were 36,696,519 shares of our common stock outstanding.

Auditor Firm ID:
34
Auditor Name:
DELOITTE & TOUCHE LLP
Auditor Location:
Houston, TX


DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s definitive proxy statement for the 2022 Annual Meeting of Stockholders, which will be filed with the SEC within 120 days of December 31, 2021, are incorporated by reference in Part III.



SANDRIDGE ENERGY, INC.
2021 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 
Item Page
PART I
1
1A.
1B.
2
3
4
PART II
5
6
7
7A.
8
9
9A.
9B.
PART III
10
11
12
13
14
PART IV
15
16



GLOSSARY OF TERMS

References in this report to the “Company,” “SandRidge,” “we,” “our,” and “us” mean SandRidge Energy, Inc., including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary. In addition, the following is a description of the meanings of certain terms used in this report.

2017 Credit Facility. Senior credit facility dated February 10, 2017, as subsequently amended.

2020 Credit Facility. Credit facility dated November 30, 2020.

2-D seismic or 3-D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions, respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.

ASC. Accounting Standards Codification.

ASU. Accounting Standards Update.

Bankruptcy Code. United States Bankruptcy Code.

Bankruptcy Court. United States Bankruptcy Court for the Southern District of Texas.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. Although an equivalent barrel of condensate or natural gas may be equivalent to a barrel of oil on an energy basis, it is not equivalent on a value basis as there may be a large difference in value between an equivalent barrel and a barrel of oil. For example, based on the commodity prices used to prepare the estimate of the Company’s reserves at year-end 2021 of $66.56/Bbl for oil and $3.60/Mcf for natural gas, the ratio of economic value of oil to natural gas was approximately 22 to 1, even though the ratio for determining energy equivalency is 6 to 1.
Boe/d. Boe per day.
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Ceiling limitation. Present value of future net revenues from proved oil, natural gas and natural gas liquids ("NGL") reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less related tax effects.

CO2. Carbon dioxide.

Completion. The process of treating a drilled well, primarily through hydraulic fracturing, followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Counterparty. Counterparty to the Company’s drilling participation agreement.

Debtors. The Company and certain of its direct and indirect subsidiaries which collectively filed for reorganization under the Bankruptcy Code on May 16, 2016.

Developed acreage. The number of acres that are assignable to productive wells.
Developed oil, natural gas and NGL reserves. Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is
1

relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development costs. Costs incurred to obtain access to proved reserves, complete wells and provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (ii) drill, equip and complete development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry well. An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Early settlements. Settlements of commodity derivative contracts prior to contractual maturity.

Emergence Date. Date the Debtors emerged from bankruptcy, October 4, 2016.

ERISA. Employee Retirement Income Security Act of 1974.

Exchange Act. Securities Exchange Act of 1934, as amended.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to produce oil or natural gas in another reservoir.
Extended-reach lateral (“XRL”). Extended-reach lateral wells are horizontal wells where the horizontal segment or lateral is at least approximately 9,000-9,500 feet in length and may extend further. When referencing lateral counts, XRL’s are counted as more than one lateral depending on the relationship of length to an SRL length. E.g. a 9,000 foot lateral would be counted as two laterals.
FASB. Financial Accounting Standards Board.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal well. A well that is turned horizontally at depth, providing access to oil and gas reserves at a wide range of angles.
Hydraulic fracturing. Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Hydraulic fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity.
IRS. Internal Revenue Service.
Lease. A contract in which the owner of minerals gives a company or working interest owner temporary and limited rights to explore for, develop, and produce minerals from the property, or; any transfer where the owner of a mineral interest assigns all or a part of the operating rights to another party but retains a continuing nonoperating interest in production from the property.
MBbls. Thousand barrels of oil or other liquid hydrocarbons.
2

MBoe. Thousand barrels of oil equivalent.
Mcf. Thousand cubic feet of natural gas.
MMBbls. Million barrels of oil or other liquid hydrocarbons.
MMBoe. Million barrels of oil equivalent.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcf/d. MMcf per day.
Mississippian Trust I. SandRidge Mississippian Trust I.

Mississippian Trust II. SandRidge Mississippian Trust II.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

North Park Basin. NPB or North Park.

NYMEX. The New York Mercantile Exchange.

NYSE. New York Stock Exchange.

Omnibus Incentive Plan. SandRidge Energy, Inc. 2016 Omnibus Incentive Plan.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues. The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.
Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities that become part of the cost of oil and natural gas produced.
Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Prospect. A specific geographic area that, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that are both proved and developed.
Proved oil, natural gas and NGL reserves. Those quantities of oil, natural gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
3

For additional information, see the SEC’s definition in Rule 4-10(a) (22) of Regulation S-X, a link for which is available at the SEC’s website.
Proved undeveloped reserves. Reserves that are both proved and undeveloped.
PV-10. See “Present value of future net revenues” above.
Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a certain date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.
Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty Interest. An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production free of costs of production.

Royalty Trust. Individually, the SandRidge Mississippian Trust I and the SandRidge Mississippian Trust II.

Royalty Trusts. Collectively, the SandRidge Mississippian Trust I and the SandRidge Mississippian Trust II.

Ryder Scott. Ryder Scott Company, L.P.

SEC. Securities and Exchange Commission.

SEC prices. Unweighted arithmetic average oil and natural gas prices as of the first day of the month for the most recent 12 months as of the balance sheet date.

Securities Act. Securities Act of 1933, as amended.

Standard-reach lateral (“SRL”). Standard-reach lateral wells are horizontal wells where the horizontal segment or lateral is approximately 4,000- 4,500 feet in length.

Standardized measure or standardized measure of discounted future net cash flows. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes on future net revenues.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
Undeveloped oil, natural gas and NGL reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.
i.Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
4

ii.Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
iii.Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
US GAAP. United States Generally Accepted Accounting Principles.
Warrants. Series A warrants and Series B warrants with initial exercise prices of $41.34 and $42.03 per share, respectively, which expire on October 4, 2022.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.




5


Cautionary Note Regarding Forward-Looking Statements

This report includes "forward-looking statements" as defined by the SEC. These forward-looking statements may include projections and estimates concerning our capital expenditures, liquidity, capital resources and debt profile, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of our business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the potential effects on our financial condition and other statements concerning our operations, financial performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements are based on certain assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected. The Company disclaims any obligation to update or revise these forward-looking statements unless required by law, and cautions readers not to rely on them unduly. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in “Risk Factors” in Item 1A of this report, as well as the following:
the impact of the COVID-19 pandemic and the effects thereof;
risks associated with drilling oil and natural gas wells;
the volatility of oil, natural gas and NGL prices;
uncertainties in estimating oil, natural gas and NGL reserves;
the need to replace the oil, natural gas and NGL reserves the Company produces;
our ability to execute our growth strategy by drilling wells as planned or other methods;
the amount, nature and timing of capital expenditures, including future development costs, required to develop our undeveloped areas;
concentration of operations in the Mid-Continent region of the United States;
limitations of seismic data;
the potential adverse effect of commodity price declines on the carrying value of our oil and natural properties;
severe or unseasonable weather that may adversely affect production;
availability of satisfactory oil, natural gas and NGL marketing and transportation options;
availability and terms of capital to fund capital expenditures;
amount and timing of proceeds of asset monetizations;
potential financial losses or earnings reductions from commodity derivatives;
potential elimination or limitation of tax incentives or tax losses and/or reduction of Net Operating Loss Carryforwards ("NOLs");
risks and uncertainties related to the adoption and implementation of regulations restricting oil and gas development in states where we operate;
competition in the oil and natural gas industry;
general economic conditions, either internationally or domestically affecting the areas where we operate;
costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing and the disposal of produced water; and
the need to maintain adequate internal control over financial reporting.
the need to protect and maintain the integrity of our Information Technology ("IT") systems and processes from vulnerabilities.
6

PART I
 
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. 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, 2021, we had an interest in 1,442 gross (817.0 net) producing wells, approximately 947 of which we operate, and approximately 551,000 gross (368,000 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.

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.

Our Business Strategy

The Company’s primary strategic focus is to grow the cash value and generation capability of our asset base in a safe, responsible and efficient manner, and will seek to use our net operating loss carry forwards to minimize income taxes and maximize cash flow. We will continue to exercise financial discipline and prudent capital allocation to projects we believe provide a high rate of return in the current commodity price environment, and will remain vigilant and maintain optionality for opportunistic, value-accretive acquisitions and business combinations.

7

PRIMARY BUSINESS OPERATIONS

A comparative discussion of our 2020 to 2019 operating results can be found in Item 1 “Business” included in our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on March 4, 2021.

Our primary operations are the development and acquisition of hydrocarbon resources. The following table presents information concerning our operations as of December 31, 2021.
Estimated 
Proved
Reserves
(MMBoe) (1)
Daily
Production
(MBoe/d)(2)
Reserves/
Production
(Years)(3)
Gross
Acreage
Net
Acreage
Capital Expenditures (In millions) (4)
Geographic Area
Mid-Continent71.3 18.5 10.6 551,000 368,000 $14.4 
____________________
(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 on page 11 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.
(4)    Capital expenditures for the year ended December 31, 2021, on an accrual basis and including acquisitions.
Properties

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. Our interests in the Mid-Continent as of December 31, 2021 included 1,442 gross (817.0 net) producing wells with an average working interest of 56.7%. 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 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.
8

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 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. 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.

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.

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 and complete;
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


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. 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,
 20212020
Cawley, Gillespie & Associates, Inc.96.2 %73.6 %
Ryder Scott Company, L.P. (1)— %17.9 %
Total96.2 %91.5 %
(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.

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, 2021 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, 2021.

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; and
Bachelor of Science Degree in Petroleum Engineering.

Reporting of Natural Gas Liquids

NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2021, NGLs comprised approximately 34% 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.

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, 2021 and 2020 approximately 96% and over 90%, 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.

10

See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.
 December 31,
 20212020
Estimated Proved Reserves (1)
Developed
Oil (MMBbls)7.9 8.5 
NGL (MMBbls)24.3 11.2 
Natural gas (Bcf)234.7 102.9 
Total proved developed (MMBoe)71.3 36.9 
Undeveloped
Oil (MMBbls)— — 
NGL (MMBbls)— — 
Natural gas (Bcf)— — 
Total proved undeveloped (MMBoe)— — 
Total Proved
Oil (MMBbls)7.9 8.5 
NGL (MMBbls)24.3 11.2 
Natural gas (Bcf)234.7 102.9 
Total proved (MMBoe)71.3 36.9 
Standardized Measure of Discounted Net Cash Flows (in millions) (2)
$432.9 $105.0 
PV-10 (in millions) (3)$432.9 $105.0 
____________________
(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. 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)
 Oil
(per Bbl)
Natural gas
(per Mcf)
Oil
(per Bbl)
NGL
(per Bbl)
Natural gas
(per Mcf)
December 31, 2021$66.56 $3.60 $64.95 $19.26 $2.56 
December 31, 2020$39.57 $1.99 $36.54 $6.40 $0.87 
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(a)    Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas. These are SEC prices calculated by using trailing 12 month average from the first trading day close of each calendar month.
(b)    Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, regional price differentials and excludes any impact of derivatives.
(c)    For 2021, the estimated proved reserves include Mid-Continent only. 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.

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(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,
 20212020
 (In millions)
Standardized Measure of Discounted Net Cash Flows$432.9 $105.0 
Present value of future income tax discounted at 10%— — 
PV-10$432.9 $105.0 

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 Undeveloped Reserves.

There were no proved undeveloped reserves at December 31, 2021 and 2020.

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.








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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.
Year Ended December 31,
20212020
Production data (in thousands)
Oil (MBbls)957 2,084 
NGL (MBbls)2,267 2,694 
Natural gas (MMcf)21,417 23,552 
Total volumes (MBoe) 6,793 8,703 
Average daily total volumes (MBoe/d) 18.6 23.8 
Average prices—as reported (1)
Oil (per Bbl)$65.10 $35.33 
 NGL (per Bbl)$22.42 $6.67 
Natural gas (per Mcf)$2.60 $0.97 
Total (per Boe)$24.86 $13.15 
Expenses per Boe
Production costs (2)$5.30 $4.99 
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(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.

Productive Wells

The following table presents the number of productive wells in which we owned a working interest at December 31, 2021. We operate substantially all of our net wells. 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.

 OilNatural GasTotal
 GrossNetGrossNetGrossNet
Geographic Area
Mid-Continent1,121 615 321 202 1,442 817 

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.

Developed and Undeveloped Acreage

The following table presents information regarding our developed and undeveloped acreage at December 31, 2021. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.
 Developed AcreageUndeveloped Acreage
 GrossNetGrossNet
Geographic Area
Mid-Continent465,449 338,684 85,583 29,802 


Less than 10% 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
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establish production from the leasehold acreage prior to expiration, which would keep the lease from expiring until production has ceased.

As of December 31, 2021, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows:
 Acres Expiring
 GrossNet
Twelve Months Ending
December 31, 20222,120 1,622 
December 31, 2023— — 
December 31, 2024566 339 
December 31, 2025 and later— — 
Other (1)82,897 27,841 
Total85,583 29,802 
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(1)Leases remaining in effect until development efforts or production on the particular lease has ceased.

Marketing and Customers

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. 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 available purchasers and markets in the areas where we sell our production reduces the risk that loss of a single downstream 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 development 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 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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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. 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.

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Hazardous Substances and Wastes

We currently own, lease, or operate, and in the past have owned, leased, or operated, sold or transferred properties that have been used in the exploration and production of oil and natural gas. We believe we have utilized operating and disposal practices that were standard in the industry at the applicable time, but hazardous substances, hydrocarbons, and wastes may have been disposed or released on, from or under the properties owned, leased, or operated by us or on or under other locations where these substances and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose storage treatment and disposal or release of hazardous substances, hydrocarbons, and wastes were not under our control. These properties and the substances or wastes disposed or released on them may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), the federal Resource Conservation and Recovery Act, (“RCRA”), and analogous state laws. Under these laws, we could be required to investigate, monitor, remove or remediate previously disposed substances or wastes (including substances or wastes disposed of or released by prior owners or operators or third parties whose waste was commingled with ours), to investigate and clean up contaminated property, to perform corrective actions to prevent future contamination, or to pay some or all of the costs of any such action.

CERCLA, also known as the Superfund law, and comparable state laws may impose strict, joint and several liability without regard to fault or legality of conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These 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. 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 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
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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. 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. On October 22, 2019, EPA and the Corps published a final rule repealing the 2015 WOTUS rule, and EPA and the Corps promulgated the Navigable Waters Protection Rule on April 21, 2020, which provides a revised definition of WOTUS and became effective on June 22, 2020. These regulations have been challenged in federal court, and on August 30, 2021 the U.S. 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. 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. 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 injuries. Some states have considered laws mandating flowback and produced water recycling. Other states have undertaken
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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 past 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 CO2, 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
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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 announced that it intends to review the September 2020 rules under President Biden’s Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis. On June 30, 2021, Congress issued a joint resolution pursuant to the Congressional Review Act disapproving the September 2020 rule, and on November 15, 2021, EPA issued a proposed rule to revise the Quad Oa regulations that, if finalized, would require methane emissions reductions and implementation of a fugitive emissions monitoring and repair program. 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. 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, 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.

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, the United States announced it would withdraw from the Paris Agreement, which became effective November 4, 2020. The United States has rejoined the Paris Agreement as of February 19, 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 restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure
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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.

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. 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 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
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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, 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. At the state level, some states, including Oklahoma and Kansas, 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.

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
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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.

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 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
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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.
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
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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 3, 2022 and December 31, 2021, we had 101 full-time employees, including 85 field employees and 16 corporate employees. At December 31, 2020, we had 114 full-time employees, including 98 field employees and 16 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 routinely evaluate our HSE processes, systems, equipment and other factors to ensure they remain aligned with our focus on risk reduction, and get us closer to zero incidents.

During 2021, our experience and continuing focus on workplace safety has enabled us to preserve business continuity without sacrificing our commitment to keeping our colleagues and workplace visitors safe during the COVID-19 pandemic.


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Item 1A. Risk Factors

An investment in our common stock involves certain risks. If any of the following key risks were to develop into actual events, it could have a material adverse effect on our financial position, results of operations and cash flows. In any such circumstance and others described below, the trading price of our securities could decline and you could lose part or all of your investment.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control. Declines in oil, natural gas or NGL prices significantly affect our financial condition and results of operations.
Our revenues, profitability and cash flow are highly dependent upon the prices we realize from the sale of oil, natural gas and NGLs. Historically, the markets for these commodities are very volatile. Prices for oil, natural gas and NGLs can move quickly and fluctuate widely in response to a variety of factors that are beyond our control. These factors include, among others:
changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGLs, as well as perceptions of supply of, and demand for, oil, natural gas and NGLs generally;
the price and quantity of foreign imports;
the amount of exports from the U.S.;
U.S. and worldwide political and economic conditions, including armed conflict and related sanctions;
the level of global and U.S. inventories and reserves;
weather conditions and seasonal trends;
anticipated future prices of oil, natural gas and NGLs, alternative fuels and other commodities;
technological advances affecting energy consumption and energy supply;
the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;
natural disasters and other extraordinary events;
domestic and foreign governmental regulations and taxation;
energy conservation and environmental measures;
the price and availability of alternative fuels;
the strength or weakness of the U.S. dollar to other currencies;
inflation and ability to acquire critical material, equipment or services in a timely or cost effective manner; and
availability of capital or level of hedging across the energy industry in the U.S. and internationally.
These factors and the volatility of the energy markets, which we expect will continue, make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. For oil, from January 2017 through December 2021, the NYMEX settled price fluctuated between a high of $85.64 per Bbl and a low of $(36.98) per Bbl. For natural gas, from January 2017 through December 2021, the month-end NYMEX settled price fluctuated between a high of $23.86 per MMBtu and a low of $1.33 per MMBtu. In addition, the market price of natural gas is generally higher in the winter months than during other months of the year due to increased demand for natural gas for heating purposes during the winter season. For NGLs, prices exhibited similar volatility from January 2017 through December 2021.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. Furthermore, even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. Decisions to develop properties depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The estimated cost of drilling, completing and operating wells is uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a
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particular project uneconomical. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of various factors, including among others the following:
reductions in oil, natural gas and NGL prices;
delays imposed by or resulting from compliance with regulatory requirements including permitting;
unusual or unexpected geological formations and miscalculations;
shortages of or delays in obtaining equipment and qualified personnel;
shortages of or delays in obtaining water and sand for hydraulic fracturing operations;
equipment malfunctions, failures or accidents;
lack of available gathering or midstream facilities or delays in construction of gathering or midstream facilities;
lack of available capacity on interconnecting transmission pipelines;
lack of adequate electrical infrastructure and water disposal capacity;
unexpected operational events and drilling conditions;
pipe or cement failures and casing collapses;
pressures, fires, blowouts and explosions;
lost or damaged drilling and service tools;
loss of drilling fluid circulation;
uncontrollable flows of oil, natural gas, brine, water or drilling fluids;
natural disasters;
environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing;
compliance with environmental and other governmental requirements;
adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes;
oil and natural gas property title problems;
market and midstream limitations for oil, natural gas and NGLs;
unexpected subsurface conditions;
lack of hydrocarbon content; and
low pressure, depletion from existing wells, parent / child effect, or other conditions that may reduce ultimate recovery of reserves.
Certain of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties.

Market conditions or operational impediments may hinder our access to oil, natural gas and NGL markets or delay production of oil, natural gas and NGLs.
Market conditions or a lack of satisfactory oil and natural gas transportation arrangements may hinder our access to oil, natural gas and NGL markets or delay production of oil, natural gas and NGLs. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for and supply of oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and treating facilities for oil, natural gas and NGLs as well as gathering systems, treating facilities and disposal wells for water produced alongside the hydrocarbons. Our failure to obtain such services on acceptable terms in the future or to expand our midstream assets could have a material adverse effect on our business. We may be required to shut in wells for a lack of a market or because access to natural gas pipelines,
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gathering system capacity, treating facilities or disposal wells may be limited or unavailable. We would be unable to realize revenue from any shut-in wells until production arrangements were made to deliver the production to market.

A financial downturn could negatively affect our business, results of operations, financial condition and liquidity.
Actual or anticipated declines in domestic or foreign economic growth rates, regional or worldwide increases in tariffs or other trade restrictions, turmoil affecting the U.S. or global financial system and markets and a severe economic contraction either regionally or worldwide, resulting from current efforts to contain the COVID-19 coronavirus or other factors, could materially affect our business and financial condition and impact our ability to finance operations by worsening the actual or anticipated future drop in worldwide commodity demand, negatively impacting the price we receive for our oil and natural gas production. Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers. All of the foregoing may adversely affect our business, financial condition, results of operations, and cash flows.
Future drilling activities face substantial uncertainties.
Our ability to drill and develop wells on our existing acreage depends on a number of uncertainties, including oil and natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering and midstream system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if certain locations will ever drilled or if we will be able to produce natural gas or oil from any of our potential locations.

Our acreage must be drilled before lease expiration, generally within three to five years of the original date of the lease, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in additional renewal cost, or if renewal is not feasible or economically desirable, loss of our lease and prospective drilling opportunities.
Leases on our oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres, or the leases are renewed. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Unless we begin drilling, we could lose undeveloped acreage through lease expirations. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to develop such acreage.

Our development operations or ability to acquire oil and gas properties and reserves require substantial capital. Outside our cash assets, we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and our ability to offset the natural decline in our oil, natural gas and NGL reserves, which would adversely affect our business, financial condition and results of operations.
The oil and natural gas industry is capital intensive. Our future oil, natural gas and NGL reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current estimated proved reserves and finding or acquiring additional economically recoverable reserves. We make substantial capital expenditures in our business and operations for the acquisition, development and production of oil, natural gas and NGL reserves. Historically, we have financed capital expenditures primarily with cash generated by operations, credit facility borrowings and proceeds from asset sales. In particular, cash flow from operations were $110.3 million and $36.2 million for the years ended December 31, 2021 and 2020, respectively.

The capital markets that we have historically accessed have recently been and may continue to be constrained to such an extent that debt or equity capital raises are practically unfeasible. If the debt and equity capital markets are not accessible, we may be unable to implement our development plans or otherwise carry out our business strategy as expected. Our cash flow from operations and access to capital are subject to a number of variables, including:
the prices at which oil, natural gas and NGLs are sold;
our proved reserves;
the level of oil, natural gas and NGLs we are able to produce from existing wells;
our ability to acquire, locate and produce new reserves; and
our capital and operating costs.
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Further, we may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which could adversely affect our business, financial condition, access to capital and results of operations.

Disruptions in the global financial and capital markets could also adversely affect our ability to obtain debt or equity financing on favorable terms, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to development of prospects, which in turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGL reserves.

Future price declines may result in reductions of the asset carrying values of our oil and natural gas properties.
We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this accounting method, all costs for both productive and nonproductive properties are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. However, the amount of these costs that can be carried as capitalized assets is subject to a ceiling, which limits such pooled costs to the aggregate of the present value of future net revenues of proved oil, natural gas and NGL reserves attributable to proved properties, discounted at 10%, plus the cost of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the SEC prices, adjusted for the impact of derivatives accounted for as cash flow hedges, if any. The Company did not recognize any full cost ceiling impairment charges for the year ended December 31, 2021. The Company incurred full cost ceiling impairment charges of $218.4 million for the year ended December 31, 2020. Cumulative full cost ceiling impairment from the Emergence Date through December 31, 2021 totaled $947.1 million. If oil, natural gas and NGL prices decline further in the near term, and without other mitigating circumstances, we may experience additional losses of future net revenues, including losses attributable to quantities that cannot be economically produced at lower prices, which would likely cause us to record additional write-downs of capitalized costs of oil and natural gas properties and non-cash charges against future earnings. The amount of such future write-downs and non-cash charges could be substantial.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves. Our current estimates of reserves could change, potentially in material amounts, in the future.
The process of estimating oil, natural gas and NGL reserves is complex and inherently imprecise, requiring interpretations of available technical data and many assumptions, including assumptions relating to production rates and economic factors such as historic oil and natural gas prices, drilling and operating expenses, capital expenditures, the assumed effect of governmental regulation and availability of funds for development expenditures. Inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. See “Business—Primary Business Operations” in Item 1 of this report for information about our oil, natural gas and NGL reserves.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves will vary and could vary significantly from our estimates shown in this report, which in turn could have a negative effect on the value of our assets. In addition, from time to time in the future, we will adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development, changes in oil, natural gas and NGL prices and other factors, many of which are beyond our control.

The ability to attract and retain key personnel is critical to the success of our business and the loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations.
The success of our business depends on key personnel, including members of senior management and technical personnel. The ability to attract and retain these key personnel may be difficult in light of the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. The market for qualified personnel has historically been, and we expect that it will continue to be, intensely competitive. We cannot assure that we will be successful in attracting or retaining such personnel. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

We are subject to litigation and adverse outcomes in such litigation could have a material effect on our financial condition.
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We are, and from time to time may become, subject to litigation and various legal proceedings, including stockholder derivative suits, class action lawsuits and other matters, that involve claims for substantial amounts of money or for other relief or that might necessitate changes to our business or operations. Additionally, we remain a nominal defendant in certain litigation matters discussed in Item 3. “Legal Proceedings,” for the purposes of fulfilling indemnification obligations for legal expenses, including any settlement amounts, to certain former officers of the Company and the SandRidge Mississippian Trust I. The defense of these actions has been and may continue to be both time consuming and expensive. We evaluate these litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we may establish reserves and/or disclose the relevant litigation claims or legal proceedings, as and when required or appropriate. These assessments and estimates are based on information available to management at the time of such assessment or estimation and involve a significant amount of judgment. As a result, actual outcomes or losses could differ materially from those envisioned by our current assessments and estimates. Our failure to successfully defend or settle any litigation or legal proceedings could result in liability that, to the extent not covered by our insurance, could have a material effect on our business, financial condition and results of operations.

Changes affecting the availability of the London Inter-bank Offered Rate (“LIBOR”) may have consequences for us that cannot yet be reasonably predicted.
The LIBOR benchmark has been the subject of national, international and other regulatory guidance and proposals to reform. In July 2017, the United Kingdom Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. In March 2021, ICE Benchmark Administration, the administrator for LIBOR, ceased publishing United States Dollar LIBOR (“USD LIBOR”) for one week and two-month tenors after December 31, 2021, and confirmed its intention to cease all remaining USD LIBOR tenors after June 30, 2023. Concurrently, the United Kingdom Financial Conduct Authority announced the cessation or loss of representativeness of the USD LIBOR tenors from those dates. The Alternative Reference Rates Committee, a group of market participants convened by the United States Federal Reserve Board and the Federal Reserve Bank of New York, has recommended the Secured Overnight Financing Rate (“SOFR”), a rate calculated based on repurchase agreements backed by United States Treasury securities, as its recommended alternative benchmark rate to replace USD LIBOR. At this time, it is not known whether or when SOFR or other alternative reference rates will attain market traction as replacements for LIBOR. These reforms may cause LIBOR to perform differently than it has in the past, and LIBOR will cease to exist after June 30, 2023. After the cessation of LIBOR, alternative benchmark rates will replace LIBOR and could affect our debt securities, debt payments and receipts. At this time, it is not possible to predict the effect of any changes to LIBOR, any phase out of LIBOR or any establishment of alternative benchmark rates. Any new benchmark rate will likely not replicate LIBOR exactly, which could impact our contracts that terminate after June 30, 2023. There is uncertainty about how applicable law and the courts will address the replacement of LIBOR with alternative rates on variable rate retail loan contracts and other contracts that do not include alternative rate fallback provisions. After June 30, 2023, the interest rates on our revolving credit facility and our term loan facility will be based on the Base Rate or an alternative benchmark rate (which may or may not be based on SOFR), which may result in higher interest rates. In addition, any changes to benchmark rates may have an uncertain impact on our cost of funds and our access to the capital markets, which could impact our results of operations and cash flows. Uncertainty as to the nature of such potential changes may also adversely affect the trading market for our securities.

The present value of future net cash flows from our proved reserves calculated in accordance with SEC guidelines are not the same as the current market value of our estimated oil, natural gas and NGL reserves.
We base the estimated discounted future net cash flows from our proved reserves on 12-month average index prices and costs, as is required by SEC rules and regulations. Actual future net cash flows from our oil and natural gas properties will be affected by actual prices we receive for oil, natural gas and NGLs, as well as other factors such as:
the actual cost of development and production expenditures;
the amount and timing of actual production;
supply of and demand for oil, natural gas and NGLs; and
changes in governmental regulation or taxation.
The timing of both our production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, we use a 10% discount factor when calculating discounted future net cash flows, which may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

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We will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible.
The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive or may suffer from declining production faster than anticipated. The use of seismic data and other technologies and the study of producing fields in the same area do not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable.

Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather.
Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather. Repercussions of natural disasters or severe weather conditions may include:
evacuation of personnel and curtailment of operations;
damage to drilling rigs or other facilities, resulting in suspension of operations;
inability to deliver materials to worksites; and
damage to, or shutting in of, pipelines and other transportation facilities.

In addition, our hydraulic fracturing operations require significant quantities of water. Regions in which we operate may experience drought conditions from time to time. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail our operations or otherwise result in delays in operations or increased costs.

The capital markets could be volatile, and such volatility could adversely affect our ability to obtain capital, cause us to incur additional financing expense or affect the value of certain assets.
In some cases, financial markets produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial and/or operating strength. Volatility in the capital markets can significantly increase the cost of raising money in the debt and equity capital markets. Generally, future market volatility and risk of persistent weakness in commodity prices may adversely affect our ability to access capital and credit markets or to obtain funds at low interest rates or on other advantageous terms. These factors may adversely affect our business, results of operations or liquidity.

Adverse credit and capital market conditions may require us to reduce the carrying value of assets associated with any derivative contracts to account for non-performance by, or increased credit risk from, counterparties to those contracts. If financial institutions that extended credit commitments to us are adversely affected by volatile conditions of the U.S. and international capital markets, they may become unable to fund borrowings under their credit commitments to us, which could have a material adverse effect on our financial condition and ability to borrow funds, if needed, for working capital, capital expenditures and other corporate purposes.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.
Our initial technical reviews of properties we acquire are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well and environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with acquired properties, and such risks and liabilities could have a material adverse effect on our results of operations and financial condition.

A significant portion of our operations are located in the Mid-Continent region, making us vulnerable to risks associated with operating in a limited number of major geographic areas.
Substantially all of our production and reserves were located in the Mid-Continent region. We divested all of our North Park Basin assets in February 2021, making substantially all of our future proved reserves and production located in the Mid-Continent. This concentration could disproportionately expose us to operational and regulatory risk in this area. This relative
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lack of diversification in location of our key operations could expose us to adverse developments in the Mid-Continent or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production due to weather, electrical outages, treatment plant closures for scheduled maintenance, changes in the regulatory environment or other factors. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more diversified.

Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which we may not be adequately insured.
There are a variety of operating risks inherent in oil, natural gas and NGL production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blowouts, uncontrollable flow of oil, natural gas and NGLs, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of oil, natural gas and NGLs at any of our properties could have a material adverse impact on our business activities, financial condition and results of operations.

Additionally, if any of such risks or similar accidents occur, we could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If we experience any of these problems, our ability to conduct operations could be adversely affected. While we maintain insurance coverage that we deem appropriate for these risks, our operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance.

Shortages or increases in costs of equipment, services and qualified personnel could adversely affect our ability to execute our development plans on a timely basis and within our budget.
The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Additionally, higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly affect our ability to execute our development plans as projected.

Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.
The oil and natural gas industry is intensely competitive, and we compete with many companies that have greater financial and other resources than we do. Many of these companies not only explore for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration and development activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas. In addition, the use of such technology requires greater predrilling expenditures, which could adversely affect the economic results of drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are present in those structures. Other geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than our professionals. Our drilling activities may not be geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not improve as a result of using 2-D and 3-D seismic data.

The use of 2-D and 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses due to such expenditures. In addition, we may often gather 2-D and 3-D seismic data over large areas in order to help us delineate those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in such location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D seismic data without having an opportunity to benefit from those expenditures.

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Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to enter into future traditional debt financing.
Inflation can adversely affect us by increasing costs of critical materials, equipment, labor, and other services. In addition, inflation is often accompanied by higher interest rates. Continued inflationary pressures could impact our profitability. Inflation may also affect our ability to enter into future traditional debt financing, as high inflation may result in an increase in cost.

As we outsource functions, we become more dependent on the entities performing those functions. Disruptions or delays at our third-party service providers could adversely impact our operations.
As part of our long-term profitable growth strategy, we are continually looking for opportunities to provide essential business services in a more cost-effective manner. In some cases, this requires the outsourcing of functions or parts of functions that can be performed more effectively by external service providers. For example, we currently outsource a significant portion of our accounting functions to third-party service providers. While we believe we conduct appropriate diligence before entering into agreements with any outsourcing entity, the failure of one or more of such entities to meet our performance standards and expectations, including with respect to providing services on a timely basis or providing services at the prices we expect, may have an adverse effect on our results of operations or financial condition. For example, our outsourcing entities and other third-party service providers may experience difficulties, disruptions, delays, or failures in their ability to deliver services to us as a result of the COVID-19 pandemic. We could face increased costs or disruption associated with finding replacement vendors or hiring new employees in order to return these services in-house, which may have a significant impact on the cost of operations. Any failures of these vendors to properly deliver their services could similarly have a material effect on our business. We may outsource other functions in the future, which would increase our reliance on third parties.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost,     manner or feasibility of conducting our operations or expose us to significant liabilities.
Our oil and natural gas development, production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these laws and regulations. As a result of recent incidents involving the release of oil and natural gas and fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state levels to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on our business, financial condition and results of operations. We must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent we are a shipper on interstate pipelines, we must comply with the FERC-approved tariffs of such pipelines and with federal policies related to the use of interstate capacity.

Laws and regulations governing oil and natural gas operations may also affect production levels. We are required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of our oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; and the plugging and abandonment of wells. These and other laws and regulations can limit the amount of oil and natural gas we can produce from our wells, limit the number of wells we can drill, or limit the locations at which we can conduct drilling operations.

Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may increase capital costs for us and third-party downstream oil and natural gas transporters. These and other potential regulations could increase our operating costs, reduce our liquidity, delay our operations, increase direct and third-party post production costs or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid for transportation on downstream interstate pipelines.

Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, the FTC or other regulators, we could be subject to substantial penalties and fines.
Under the EPAct 2005 and implementing regulations, the FERC prohibits market manipulation in connection with the purchase or sale of natural gas. The CFTC has similar authority under the Commodity Exchange Act and regulations it has promulgated thereunder with respect to certain segments of the physical and futures energy commodities market including oil
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and natural gas. The FTC also prohibits manipulative or fraudulent conduct in the wholesale petroleum market with respect to sales of commodities, including crude oil, condensate and natural gas liquids. Other regulatory entities have jurisdiction over our industry and operations. These agencies have substantial enforcement authority, including the ability to impose penalties for current violations in excess of $1 million per day for each violation. The FERC has also imposed requirements related to reporting of natural gas sales volumes that may impact the formation of prices indices. Additional rules and legislation pertaining to these and other matters may be considered or adopted from time to time. Our failure to comply with these or other laws and regulations administered by these agencies could subject us to criminal and civil penalties, as described in Item 1. “Business— Other Regulation of the Oil and Natural Gas Industry.”

Our operations are subject to environmental and occupational safety and health laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations or result in significant costs and liabilities.
Our oil and natural gas operations are subject to stringent and complex federal, state, tribal, regional and local laws and regulations governing worker safety and health, the discharge and disposal of substances into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in litigation; the assessment of sanctions, including administrative, civil or 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 and injunctions limiting or preventing some or all of our operations in affected areas.

Under certain environmental laws and regulations, we could be subject to strict, and/or joint and several liability for the investigation, removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled or facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, to seek damages for contamination, for personal injury, natural resources damage or property damage.

Changes in environmental laws and regulations occur frequently, and any changes 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 require significant expenditures by us to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and natural gas production. We routinely have utilized hydraulic fracturing techniques in the majority of our drilling and completion programs. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAA final regulations in 2012 and additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry; 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 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 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, and after various appeals and a presidential executive order directing it to review rules related to the energy industry, the BLM published a final rule rescinding the 2015 rule in December 2017.

From time to time, the U.S. Congress has considered adopting legislation intended 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. In addition, certain states, including Oklahoma, have adopted regulations that could impose new or more stringent permitting, disclosure, and well-construction requirements on hydraulic fracturing operations. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted at the local, state or federal level, fracturing activities with respect to our properties could become subject to additional permit requirements, reporting requirements or operational restrictions, which may result in permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable.
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Restrictions on hydraulic fracturing could also reduce the amount of oil, natural gas or NGLs that are ultimately produced in commercial quantities from our properties.

Legislation or regulatory initiatives intended to address seismic activity are restricting and could restrict our ability to dispose of saltwater produced alongside our hydrocarbons, which could limit our ability to produce oil and natural gas economically and have a material adverse effect on our business.
Large volumes of saltwater produced alongside our oil, natural gas and NGLs in connection with drilling and production operations are disposed of pursuant to permits issued by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

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, which could negatively affect the economic lives of our properties.

Refer to “—Environmental Regulations— Subsurface Injections” included in Item 1 of this report for additional discussion of the current and potential impacts of legislation or regulatory initiatives related to seismic activity on our operations.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
The EPA previously published its findings that emissions of GHGs present a danger to public health and the environment because such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted various rules to address GHG emissions under existing provisions of the CAA. For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis, which includes certain of our operations. In addition, 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 an LDAR program to minimize methane emissions, under the CAA’s New Source Performance Standards Quad Oa. However, the EPA has taken several steps to delay implementation of the Quad Oa standards. The agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and 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 when meeting certain Quad Oa requirements is technically infeasible. 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. 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. It is possible that these rules will continue to require oil and gas operators to expend material sums.

In addition, in November 2016, the BLM issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on public lands that are substantially similar to the EPA Quad Oa requirements. However, on December 8, 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 to revise or rescind certain provisions of the 2016 rule. 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. While, as a result of these developments, future implementation of the EPA and BLM methane rules is uncertain, given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility. 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.
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In addition, there are a number of state and regional efforts that 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 was one of almost 200 nations that agreed in December 2015 to the Paris Agreement. However, the Paris Agreement did 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. On January 20, 2021, President Joe Biden rejoined the Paris Agreement.

The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and our operations could require us to incur additional costs to monitor, report and potentially reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that 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 development and production activities. 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 could 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 our assets and operations, and potentially subject us to greater regulation.

Carbon capture technology and sequestration is not currently deployed on a wide-spread basis, and regulations are not developed.
Carbon capture and sequestration of the CO2 is an emerging technology. While the technology to capture CO2 from refining is available, it is not in wide-spread use. Sequestering the CO2 after it is captured in underground formations is a new technology and the regulations and legal framework is evolving. Today the technical, legal and regulatory framework for injecting CO2 may change dramatically over time and may adversely impact our business model.

Our failure to maintain an adequate system of internal control over financial reporting, could adversely affect our ability to accurately report our results.
Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. A material weakness is a deficiency, or a combination of deficiencies, in our internal control over financial reporting that results in a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Effective internal controls are necessary for us to provide reliable financial reports and deter and detect any material fraud. If we cannot provide reliable financial reports or prevent material fraud, our reputation and operating results would be harmed. We maintained effective internal control over financial reporting as of December 31, 2021, as further described in Part II “Item 9A—Controls and Procedures” and “Management’s Report on Internal Control over Financial Reporting.” Our efforts to develop and maintain our internal controls and to remediate any material weaknesses in our controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation, including those related to acquired businesses, or other effective improvement of our internal controls could harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation, which could adversely affect our ability to hedge risks associated with our business.
We may enter into financial derivative instruments with respect to a portion of our production to manage our exposure to oil, gas, and NGL price volatility. To the extent that we engage in price risk management activities to protect the Company from commodity price declines, we would be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the contract counterparties fail to perform under the contracts. Further, to date, we have not designated and do not currently plan to designate any of our derivative contracts as hedges for accounting purposes and, as a result, record all derivative contracts on our balance sheet at fair value with changes in fair value
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recognized in current period earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") Act created a new regulatory framework for oversight of derivatives transactions by the CFTC and the SEC. Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility, unless the “end-user” exception from clearing applies. The Dodd-Frank Act also established a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets and also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into for bona fide hedging purposes).

There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. However, although we may qualify for exceptions, our derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act, which may increase our transaction costs or make it more difficult for us to enter into hedging transactions on favorable terms.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter and reduce our ability to monetize or restructure derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

Cyber-attacks or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations.
In recent years, we have increasingly relied on information technology systems and networks in connection with our business activities, including certain of our acquisition, development and production activities. We rely on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. These threats pose a risk to the security of our systems and networks, the confidentiality, availability and integrity of our data and the physical security of our employees and assets. We have experienced, and expect to continue to confront, attempts from hackers and other third parties to gain unauthorized access to our information technology systems and networks. Although prior cyber-attacks have not had a material adverse impact on our operations or financial performance, there can be no assurance that we will be successful in preventing cyber-attacks or successfully mitigating their effect. Any cyber-attack could have a material adverse effect on our reputation, competitive position, business, financial condition and results of operations. Cyber-attacks or security breaches also could result in litigation or regulatory action, as well as significant additional expense to implement further data protection measures.

In addition to the risks presented to our systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets. A cyber-attack of this nature would be outside our control, but could have a material, adverse effect on our business, financial condition and results of operations.

We have programs, processes and technologies in place to attempt to prevent, detect, contain, respond to and mitigate security-related threats and potential incidents. We undertake ongoing improvements to our systems, connected devices and information-sharing products in order to minimize vulnerabilities, in accordance with industry and regulatory standards; however, because the techniques used to obtain unauthorized access change frequently and can be difficult to detect,
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anticipating, identifying or preventing these intrusions or mitigating them if and when they occur is challenging and makes us more vulnerable to cyber-attacks than other companies not similarly situated.

If our security measures are circumvented, proprietary information may be misappropriated, our operations may be disrupted, and our computers or those of our customers or other third parties may be damaged. Compromises of our security may result in an interruption of operations, violation of applicable privacy and other laws, significant legal and financial exposure, damage to our reputation, and a loss of confidence in our security measures.

Repercussions from terrorist activities or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts or other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues. Oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and/or operations could be adversely impacted if infrastructure integral to our operations is destroyed by such attacks. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Relating to COVID-19

The COVID-19 pandemic could adversely affected our business, and the ultimate effect on our operations and financial condition will depend on future developments, which are highly uncertain and cannot be predicted.
The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets. In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there was a significant reduction in demand for and prices of crude oil, natural gas and NGL. If the reduced demand for and prices of crude oil, natural gas and NGL continue for a prolonged period, our operations, financial condition, cash flows, level of expenditures and the quantity of estimated proved reserves that may be attributed to our properties may be materially and adversely affected. Our operations also may be adversely affected if significant portions of our workforce are unable to work effectively, including because of illness, quarantines, government actions, or other restrictions in connection with the pandemic. We have implemented workplace restrictions, including guidance for our employees to work remotely if necessary, in our offices and work sites for health and safety reasons and are continuing to monitor national, state and local government directives where we have operations and/or offices. The extent to which the COVID-19 pandemic adversely affects our business, results of operations, and financial condition will depend on future developments, which are highly uncertain and cannot be predicted, including the scope and duration of the pandemic and actions taken by governmental authorities and other third parties in response to the pandemic.

Price Fluctuations, Global Supply Chain Disruptions and Inflation may Adversely Impact our Results of Operations.
With the global economic uncertainty surrounding the COVID-19 pandemic and its severity and duration and supply chain disruptions, we may continue to incur significant prices increases in the future which would likely have an adverse effect on our operating margins. The disruptions to the global economy in 2020 and into 2021 have impeded global supply chains, resulting in longer lead times and also increased costs. We have taken steps to minimize the impact of these increased costs by working closely with our suppliers. Despite the actions we have undertaken to minimize the impacts from disruptions to the global economy, there can be no assurances that unforeseen future events in the global supply chain, and inflationary pressures, will not have a material adverse effect on our business, financial condition and results of operations.

Labor shortages and increased turnover or increases in employee and employee-related costs could have adverse effects on our profitability.

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While we have historically experienced some level of ordinary course turnover of employees, the COVID-19 pandemic and resulting actions and impacts have exacerbated labor shortages and increased turnover. A number of factors have had and may continue to have adverse effects on the labor force available to us, including reduced employment pools, federal unemployment subsidies, including unemployment benefits offered in response to the COVID-19 pandemic, and other government regulations, which include laws and regulations related to workers’ health and safety, wage and hour practices. Labor shortages and increased turnover rates within our team members have led to and could in the future lead to increased costs, such as increased overtime to meet demand and increased wage rates to attract and retain employees and could negatively affect our ability to efficiently operate our production facilities or otherwise operate at full capacity. An overall or prolonged labor shortage, lack of skilled labor, increased turnover or labor inflation could have a material adverse impact on our operations, results of operations, liquidity or cash flows.

Risks Relating to our NOLs

Our ability to use our NOLs may be limited. We have adopted a Tax Benefits Preservation Plan that is designed to protect our NOLs but there is no assurance it will prevent an ownership change resulting in loss of the Company’s NOLs.
As of December 31, 2021, we had U.S. federal NOLs of $1.7 billion, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation, the majority of which will expire between 2025 and 2038, if not limited by additional triggering events prior to such time. Under the provisions of the Internal Revenue Code of 1986, as amended (“IRC”), changes in our ownership, in certain circumstances, will limit the amount of U.S. federal NOLs that can be utilized annually in the future to offset taxable income. In particular, Section 382 of the IRC imposes limitations on a company’s ability to use NOLs upon certain changes in such ownership. Generally, an “ownership change” occurs if the percentage of the Company’s stock owned by one or more of its “five-percent shareholders” (as such term is defined in Section 382 of the IRC) increases by more than 50 percentage points over the lowest percentage of stock owned by such stockholder or stockholders at any time over a three-year period. Calculations pursuant to Section 382 of the IRC can be very complicated and no assurance can be given that upon further analysis, our ability to take advantage of our NOLs may be limited to a greater extent than we currently anticipate. We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our federal NOLs. If we are limited in our ability to use our NOLs in future years in which we have taxable income, we will pay more taxes than if we were able to utilize our NOLs fully.

On July 1, 2020, our Board of Directors approved, and the Company adopted, as amended on March 16, 2021 a Tax Benefits Preservation Plan in order to protect shareholder value against a possible limitation on the Company’s ability to use its tax NOLs and certain other tax benefits to reduce potential future U.S. federal income tax obligations. The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. The Tax Benefits Preservation Plan is designed to reduce the likelihood of an “ownership change” as defined under Section 382 of the IRC in order to protect our NOLs by deterring any person or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities. However, there is no assurance that the Tax Benefits Preservation Plan will prevent all transfers that could result in such an “ownership change.”

Risks Relating to our Common Stock

The exercise of all or any number of outstanding Warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.
As of the date of filing this report, we have outstanding Warrants to purchase approximately 7.0 million shares of our common stock at average exercise prices of either $41.34 and $42.03 per share. In addition, we have as of the date of this report, 1.0 million shares of common stock reserved for future issuance under the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan (the, “Omnibus Incentive Plan”). The exercise of equity awards, including any stock options that we may grant in the future, the Warrants, and the sale of shares of our common stock underlying any such options or the Warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares. Investors may experience dilution in the net tangible book value of their investment upon the exercise of the Warrants and any stock options that may be granted or issued pursuant to the Omnibus Incentive Plan in the future.

We have adopted a Tax Benefits Preservation Plan, which may discourage a corporate takeover.
On July 1, 2020, our Board of Directors adopted a Tax Benefits Preservation Plan as amended on March 16, 2021 and declared a dividend distribution of one right for each outstanding share of our common stock to stockholders of record at the close of business on July 13, 2020. The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. Each share of our common stock issued thereafter will also include one right. Each right entitles
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its holder, under certain circumstances, to purchase from us one one-thousandth of a share of our Series A Junior Participating Preferred Stock at an exercise price of $5.00 per right, subject to adjustment.

The Board adopted the Tax Benefits Preservation Plan in an effort to protect stockholder value by attempting to protect against a possible limitation on our ability to use our NOLs. We may utilize these NOLs in certain circumstances to offset future United States taxable income and reduce our United States federal income tax liability. Because the Tax Benefits Preservation Plan could make it more expensive for a person to acquire a controlling interest in us, it could have the effect of delaying or preventing a change in control even if a change in control was in our stockholders’ interest.

Anti-takeover provisions in our charter documents and under Delaware corporate law may make it more difficult to acquire us, even though such acquisitions may be beneficial to our stockholders.
In addition to our Tax Benefits Preservation Plan, provisions of our certificate of incorporation and bylaws, as well as provisions of Delaware corporate law, could make it more difficult for a third party to acquire us, even though such acquisitions may be beneficial to our stockholders. These anti-takeover provisions include:
lack of a provision for cumulative voting in the election of directors;
the ability of our Board to authorize the issuance of “blank check” preferred stock to increase the number of outstanding shares and thwart a takeover attempt;
advance notice requirements for nominations for election to the Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings; and
limitations on who may call a special meeting of stockholders.

The provisions described above, our Tax Benefits Preservation Plan and provisions of Delaware corporate law relating to business combinations with interested stockholders may discourage, delay or prevent a third party from acquiring us. These provisions may also discourage, delay or prevent a third party from acquiring a large portion of our securities, or initiating a tender offer, even if our stockholders might receive a premium for their shares in the acquisition over the then current market price.

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Item 1B. Unresolved Staff Comments

None.

Item 2.    Properties

Information regarding the Company’s properties is included in Item 1.


Item 3.    Legal Proceedings

See "Note 13Commitments and Contingencies” to the accompanying consolidated financial statements in Item 8 of this report.

Item 4.    Mine Safety Disclosures

Not applicable.

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PART II

Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Since October 4, 2016, the Successor Company’s common stock has been listed on the New York Stock Exchange (“NYSE”) under the symbol “SD.”

On February 25, 2022, there were 330 record holders of the Company’s common stock, which does not reflect persons or entities that hold the common stock in nominee or “street” name through various brokerage firms and financial institutions.

Issuer Purchases of Equity Securities

None.

Item 6.    [Reserved].


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Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1 and “Financial Statements and Supplementary Data” in Item 8. Our discussion and analysis includes the following subjects:
Overview;
Consolidated Results of Operations;
Liquidity and Capital Resources;
Valuation Allowance; and
Critical Accounting Policies and Estimates.

We have applied the Securities and Exchange Commission’s adopted FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent calendar years. This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for years ended 2021 and 2020. For the comparison of years ended 2020 and 2019, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2020 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 4, 2021.

Overview

We are an independent oil and natural gas company with a principal focus on acquisition, development and production activities in the U.S. Mid-Continent. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.

Operational Activities

There was no drilling activity on our operated acreage during the years ended December 31, 2021 and 2020. However, we brought wells that were previously not producing on to production as part of our well reactivation program during the year ended December 31, 2021.

The chart below shows production by product for the years ended December 31, 2021 and 2020:


sd-20211231_g1.jpg
(1)For the year ended December 31, 2021, North Park Basin had 67 MBoe in oil production.
(2)For the year ended December 31, 2020, North Park Basin had 940 MBoe in oil production.

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Total production for 2021 was comprised of approximately 14.1% oil, 52.5% natural gas and 33.4% NGLs compared to 23.9% oil, 45.1% natural gas and 31.0% NGLs in 2020.

Mid-Continent total production for the year ended December 31, 2021 and 2020 was comprised of the following:

Year Ended December 31,
20212020
Oil13.2 %14.7 %
NGL33.7 %34.7 %
Natural gas53.1 %50.6 %
Total 100.0 %100.0 %

Highlighted Events


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.

On March 3, 2021, we named Mr. Salah Gamoudi, our Chief Financial Officer and Chief Accounting Officer, as a Senior Vice President. We also named Mr. Dean Parrish, formerly our Director of Operations, as our Vice President of Operations.

On April 22, 2021, we announced the acquisition of all the overriding royalty interest assets of SandRidge Mississippian Trust I (the “Trust”). The gross purchase price is $4.9 million (net $3.6 million, given our 26.9% ownership of the Trust).

On July 9, 2021, Carl F. Giesler, Jr. submitted his resignation from his positions as CEO, President and as a member of the Board of the Company, effective July 16, 2021 in order to pursue another career opportunity. Mr. Giesler did not resign as a result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

The Board appointed Grayson Pranin as President and CEO effective July 16, 2021 and in addition will maintain his role as Chief Operating Officer. Mr. Pranin, age 41, held the role of Senior Vice President and Chief Operating Officer since March 3, 2021.

In August 2021, our Board of Directors approved the initiation of a share repurchase program (the "Program") authorizing us to purchase up to an aggregate of $25.0 million of our common stock beginning as early as August 16, 2021. The Program is in accordance with Rule 10b-18 of the Exchange Act. Subject to applicable rules and regulations, repurchases under the Program can be made from time to time in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time. We did not repurchase any common stock under the Program during the year ended December 31, 2021.

On September 2, 2021, we repaid our $20.0 million term loan in full and terminated all commitments and obligations under the 2020 Credit Facility. Our repayment of the term loan satisfied all of our remaining term debt and revolving debt obligations.

On December 28, 2021, Patricia Agnello submitted her resignation from her positions as a member of the Board of Directors (the “Board”) our Company. Ms. Agnello did not resign as a result of any disagreement with the Company on any matter relating to the Company’s operations, policies or practices.

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Outlook

As discussed in “Business— Our Business Strategy” in Item 1 of this report, we will focus on growing the cash value and generation capability of our asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects we believe provide high rates of returns in the current commodity price environment. These projects include a continuation of our well reactivation program, artificial lift conversions to more efficient and cost effective systems, as well as focused drilling in high-graded areas, which will aide in partially offsetting the natural decline of our producing asset's. Forward looking commodity prices, results, costs and other factors will shape our development decisions in 2022 and beyond. We will also remain vigilant and maintain optionality for opportunistic, value-accretive acquisitions and business combinations.
As the impact of COVID-19 lessens, demand for commodities is continuing to rise to pre-pandemic levels within the United States. The resurging demand led to favorable commodity prices during the year ended December 31, 2021. However, the spread of COVID-19 variants and the effectiveness of the vaccines against these variants are significant risk factors to a full and sustained recovery. If the vaccines currently available are not effective against COVID-19 or its other variants, Governments and other regulatory bodies may have to rely on mobility and activity restrictions to mitigate the spread, which could lead to reduced demand for certain commodities. See “Item 1A. Risk Factors” included in Part I of this Annual Report for additional discussion of the potential impact these events may have on our future revenues.

Consolidated Results of Operations

The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs. Our revenues, profitability and future growth depend substantially on prevailing prices received for our production, the quantity of oil, natural gas and NGLs we produce, and our ability to find and economically develop and produce our reserves. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. To provide information on the general trend in pricing, the average annual NYMEX prices for oil and natural gas for recent years are presented in the table below:     
Year Ended December 31,
20212020
NYMEX Oil (per Bbl)$68.18 $39.19 
NYMEX Natural gas (per MMBtu)$3.90 $2.13 

In order to reduce our exposure to price fluctuations, from time to time we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oil, natural gas and NGL. Conversely, during periods of declining market prices of oil, natural gas and NGL, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement.

Acquisitions and Divestitures of Properties

2021 Acquisitions and Divestitures

On April 22, 2021, we announced the acquisition of all the overriding royalty interest assets of SandRidge Mississippian Trust I (the “Trust”). The gross purchase price is $4.9 million (net $3.6 million, given our 26.9% ownership of the Trust).

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.

2020 Acquisitions and Divestitures

On September 10, 2020, the Company acquired all of the overriding royalty interests held by SandRidge Mississippian Royalty Trust II ("the Trust") for a net purchase price of $3.28 million, given our 37.6% ownership of the Trust. The Company
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accounted for this transaction as an asset acquisition and allocated the purchase price of the acquisition plus the transactions costs to oil and gas properties.

On August 31, 2020, the Company closed on the previously announced sale of its corporate headquarters building located in Oklahoma City, OK, for net proceeds of approximately $35.4 million.

Oil, Natural Gas and NGL Production and Pricing

The table below presents production and pricing information for the years ended December 31, 2021 and 2020.

Year Ended December 31,
20212020
Production data (in thousands)
Oil (MBbls)957 2,084 
 NGL (MBbls)2,267 2,694 
Natural gas (MMcf)21,417 23,552 
Total volumes (MBoe)6,793 8,703 
Average daily total volumes (MBoe/d)18.6 23.8 
Average prices—as reported (1)
Oil (per Bbl)$65.10 $35.33 
 NGL (per Bbl)$22.42 $6.67 
Natural gas (per Mcf)$2.60 $0.97 
Total (per Boe)$24.86 $13.15 
Average prices—including impact of derivative contract settlements
Oil (per Bbl)$65.10 $40.10 
 NGL (per Bbl)$22.28 $6.67 
Natural gas (per Mcf)$2.51 $0.80 
Total (per Boe)$24.53 $13.83 
___________________
(1)Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.

The table below presents production by area of operation for the years ended December 31, 2021 and 2020.
Year Ended December 31,
20212020
Production (MBoe)% of Total ProductionProduction (MBoe)% of Total Production
Mid-Continent6,726 99.0 %7,763 89.2 %
North Park Basin67 1.0 %940 10.8 %
Total6,793 100.0 %8,703 100.0 %

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Revenues

Consolidated revenues for the years ended December 31, 2021 and 2020 are presented in the table below (in thousands).
 Year Ended December 31,
 20212020
Revenues
Oil$62,297 $73,621 
NGL50,836 17,962 
Natural gas55,749 22,867 
Other— 526 
Total revenues$168,882 $114,976 

Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the years ended December 31, 2021 and 2020 are shown in the table below (in thousands):
2020 oil, natural gas and NGL revenues

$114,450 
Change due to production volumes in 2021(47,453)
Change due to average prices in 2021101,885 
2021 oil, natural gas and NGL revenues $168,882 

Oil, natural gas and NGL revenues increased by a combined $54.4 million, or 47.6% for the year ended December 31, 2021, compared to 2020. The average prices for oil, natural gas and NGL's increased primarily due to increased oil, natural gas and NGL realized prices primarily as a result of increased economic activity and recovery from the COVID-19 pandemic and the related increase in energy demand, in addition to a contraction of differentials on realized commodity prices. These increases were partially offset by an overall decline in production due to the natural declines in our existing producing wells and a decrease in oil production as a result of the sale of NPB. Midcon production declines were reduced as a result of our well reactivation program that employs low cost capital workovers to return wells to production.

Operating Expenses

Operating expenses for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):
 Year Ended December 31,
 20212020
Lease operating expenses$35,999 $43,431 
Production, ad valorem, and other taxes9,918 9,634 
Depreciation and depletion—oil and natural gas9,372 50,349 
Depreciation and amortization—other6,073 7,736 
Total operating expenses$61,362 $111,150 
Lease operating expenses ($/Boe)$5.30 $4.99 
Production, ad valorem, and other taxes ($/Boe)$1.46 $1.11 
Depreciation and amortization—oil and natural gas ($/Boe)$1.38 $5.79 
Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue)5.9 %8.4 %

Lease operating expenses for 2021 decreased $7.4 million from 2020. This decrease primarily resulted from field personnel reductions in force, the sale of NPB and other cost reduction efforts during the year ended December 31, 2021.

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Production, ad valorem, and other taxes has increased primarily due to higher commodity prices in 2021 partially offset by a decline in ad valorem taxes due to the sale of NPB in Colorado and a difference in our accrued estimate and the actual last ad valorem tax payment made for NPB. Production, ad valorem, and other taxes decreased as a percentage of oil, natural gas and NGL revenue for the year 2021 compared to 2020, primarily due to the difference between the estimate and actual payment for ad valorem taxes of NPB.

Depreciation and depletion for oil and natural gas properties decreased by $41.0 million for the year ended December 31, 2021 compared to 2020 due to a decrease in the average depreciation and depletion rate to $1.38 per Boe in 2021 compared to an average rate of $5.79 in 2020. These decreases are primarily due to the sale of the North Park Basin properties and full cost ceiling test impairments recorded during 2020, which lowered the net cost basis of our oil and gas properties significantly.

Impairment

Impairment expense for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):
 Year Ended December 31,
 20212020
Impairment
Full cost pool ceiling limitation$— $218,399 
Other— 38,000 
Total impairment$— $256,399 

Full cost pool impairment.    We did not record a full cost ceiling limitation impairment for the year ended December 31, 2021. Impairment for the year ended December 31, 2020 largely resulted from an impairment charge of $256.4 million, which included a full cost ceiling limitation impairment charge of $218.4 million, and an impairment charge of $38 million to write down the value of the Company's building headquarters to its estimated fair value less estimated costs to sell the building headquarters.

Calculation of the full cost ceiling test is based on, among other factors, trailing twelve-month SEC prices as adjusted for price differentials and other contractual arrangements. The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2021 were $66.56 per barrel of oil and $3.60 per Mcf of natural gas, before price differential adjustments.

Based on the SEC prices over the twelve months ended March 1, 2022, we anticipate the SEC prices utilized in the March 31, 2022 full cost ceiling test may be $75.24 per barrel of oil and $4.09 per Mcf of natural gas, (the "estimated first quarter prices"). Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2021 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2022.
However, a full cost ceiling limitation impairment may still be realized in the first quarter of 2022 and in subsequent quarters based on the outcome of numerous other factors such as additional declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves. Any such ceiling test impairments in 2022 could be material to our net earnings.

Full cost pool impairments have no impact to our cash flow or liquidity.
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Other Operating Expenses

Other operating expenses for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):
Year Ended December 31,
20212020
General and administrative$9,675 $15,327 
Restructuring expenses792 2,733 
Employee termination benefits49 8,433 
(Gain) loss on derivative contracts2,251 (5,765)
(Gain) loss on sale of assets(18,952)(100)
Other operating expense (income)(382)306 
Total non-operating expenses$(6,567)$20,934 

General and administrative expenses decreased $5.7 million, or 36.9%, for the year ended December 31, 2021 compared to 2020. These decreases resulted primarily from a reduction in compensation related costs after completing reductions in force during 2020, significant reductions in information technology and software costs and overhead expenses related to the Company's previously held corporate headquarters building. Part of the decrease is also due to reductions in professional costs such as legal expenses, audit fees and consulting services.

Restructuring expenses represent fees and costs associated with the 2016 bankruptcy and exit from NPB in Colorado. Restructuring expenses decreased by $1.9 million, or 71.0% for the year ended December 31, 2021, compared to 2020. These decreases are primarily related to previously accrued expenses for the 2016 Bankruptcy that were removed as a result of the notice of completion of final distribution being filed in the United States Bankruptcy Court for the Southern District of Texas on July 26, 2021. Further, 2020 expenses included the relocation of company headquarters and outsourcing of corporate functions. See "Note 13 - Commitments and Contingencies" in the accompanying consolidated financial statements in Item 8 of this report for additional discussion of these expenses.

Employee termination benefits for the years ended December 31, 2021 and 2020, includes cash and share-based severance costs incurred for reductions in force. The decrease from 2020 to 2021 is primarily the result of separations of employment for Company employees during 2020, that did not occur in 2021. As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with the separations in 2020, with no recurrence of such costs in 2021. See "Note 13 - Employee Termination Benefits" in the accompanying consolidated financial statements in Item 8 of this report for additional discussion of these expenses.

Loss on derivative contracts of $2.3 million and a gain of $5.8 million for the years ended December 31, 2021 and 2020, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments upon settlement of $2.2 million, and net cash received upon settlement of $5.9 million, respectively.

Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded quarterly as a component of operating expenses. Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural gas production to determine “effective prices.” In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts, and cash is paid on settlement of contracts due to higher oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts. See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” of this report for additional discussion of our commodity derivatives.

(Gain) loss on sale of assets increased by $18.9 million for the year ended December 31, 2021 compared to 2020. The increase is due to the gain on sale for the sale of NPB assets in Colorado in February 2021.
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Other Income (Expense)

Other income (expense) for the years ended December 31, 2021 and 2020 is reflected in the table below (in thousands):
 Year Ended December 31,
20212020
Other (expense) income
Interest expense, net$(404)$(1,998)
Other (expense) income , net3,055 (2,494)
Total other (expense) income$2,651 $(4,492)

Interest expense for the years ended December 31, 2021 and 2020 consisted of the following (in thousands):
Year Ended December 31,
20212020
Interest expense
Interest expense on debt$377 $2,386 
 Interest expense on right of use assets 26 114 
Write off of debt issuance costs174 266 
Amortization of debt issuance costs, premium and discounts57 — 
Capitalized interest(252)(750)
Interest expense - other25 
Total 407 2,017 
Less: interest income(3)(19)
Total interest expense, net$404 $1,998 

Interest expense incurred during the year ended December 31, 2021 is primarily comprised of interest paid on the 2020 Credit Facility. The 2020 Credit Facility has been fully repaid and terminated as of September 2, 2021. As a result of the termination of the 2020 Credit Facility, $0.2 million of deferred financing costs were expensed to Interest expense. Interest expense incurred during the year ended December 31, 2020 is primarily comprised of interest and fees paid on the 2017 Credit Facility that was terminated on November 30, 2020.

See “Note 11—Long-Term Debt” to the accompanying consolidated financial statements in Item 8 of this report for additional discussion of our long-term debt transactions.

The Other (expense) income, net line item for the year ended December 31, 2021 is primarily comprised of the removal of $2.4 million of an allowance for doubtful accounts as a result of the $2.4 million being collected October 2021. For the year ended December 31, 2020, this line item includes an allowance for doubtful accounts of $2.5 million that was recorded as a result of conducting an assessment of governmental and other regulatory receivable balances, which we had previously deemed as potentially uncollectible.


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Liquidity and Capital Resources

At December 31, 2021, our cash and cash equivalents, including restricted cash, was $139.5 million. The 2020 Credit Facility was terminated, as discussed below. See "Note11 Long-Term Debt" to the accompanying consolidated financial statements in Item 8 of this report for further discussion. For the next twelve months, we expect to have ample liquidity with cash on hand and cash from operations. As of March 9, 2022, the Company had no outstanding term or revolving debt obligations.

Our commodity derivative contracts are subject to credit risk of our counterparties being financially able to settle the transaction. We monitor the credit ratings of our derivative counterparties and consider our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. However, any future failures by one or more counterparties could negatively impact our cash flow from operations.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2021 included cash flow from operations and cash on hand.

Our working capital increased to $97.7 million at December 31, 2021, compared to $18.1 million at December 31, 2020, the positive impact on working capital resulted primarily from an increase in cash and cash equivalents at December 31, 2021 as a result of proceeds from the sale of NPB and cash flows from operations. In addition, accounts payable and accrued liabilities decreased due to our continuous cost reduction efforts, the sale of NPB and the timing of payments.

We intend to spend between $41 million and $50 million in our 2022 capital budget plan, excluding any expenditures for acquisitions. We intend to fund capital expenditures and other commitments for the next 12 months using cash flows from our operations and cash on hand. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.

Cash Flows

Our cash flows from operations are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile. For example, during the period from January 2017 through December 2021, the NYMEX settled price for oil fluctuated between a high of $85.64 per Bbl and a low of $(36.98) per Bbl, and the month-end NYMEX settled price for gas fluctuated between a high of $23.86 per MMBtu and a low of $1.33 per MMBtu.

If oil or natural gas prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. This could result in full cost pool ceiling impairments. Further, if our future capital expenditures are limited or deferred, or we are unsuccessful in developing reserves and adding production through our capital program, the value of our oil and natural gas properties, financial condition and results of operations could be adversely affected.

Cash flows for the years ended December 31, 2021, and 2020 are presented in the following table and discussed below (in thousands):
 Year Ended December 31,
 20212020
Cash flows provided by (used in) operating activities$110,260 $36,162 
Cash flows provided by (used in) investing activities22,973 25,093 
Cash flows provided by (used in) financing activities(21,975)(38,957)
Net increase (decrease) in cash and cash equivalents$111,258 $22,298 

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Cash Flows from Operating Activities

The $74.1 million increase in operating cash flows for the year ended December 31, 2021 compared to 2020, is primarily due to net income of $116.7 million which is the result of improved revenue due to increased commodity prices and improved differentials as well as the well reactivation program which reduced production declines. In addition, our cost reduction efforts resulted in decreases in lease operating expenses and general and administrative expenses. The increase in net income was partially offset by the addback of the gain on sale of assets primarily related to NPB and a reduction of accrued liabilities over and above an increase in our receivable and other working capital balances.

See “—Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses.

Cash Flows from Investing Activities

During the year ended December 31, 2021, cash flows provided by investing activities primarily reflects $38.2 million of net cash proceeds primarily from the sale of NPB assets partially offset by capital expenditures of $11.6 million and the acquisition of overriding royalty interests for $3.6 million.

During the year ended December 31, 2020, cash flows provided by investing activities primarily reflects $35.4 million of net cash proceeds from the sale of the corporate office building, offset by cash payments made for capital expenditures coupled with the acquisition of $3.3 million primarily related to the purchase of overriding royalty interests.

See "Note 3Acquisitions, Divestitures and Disposal of Assets and Oil and Gas Properties" to the accompanying consolidated financial statements included in Item 8 of this report for additional information.

Capital Expenditures. 

Our capital expenditures for the years ended December 31, 2021 and 2020, are summarized below (in thousands):
 

Year Ended December 31,
 20212020
Capital Expenditures
Drilling, completion, and capital workovers$10,045 $3,563 
Leasehold and geophysical905 1,005 
Capital expenditures, excluding acquisitions (on an accrual basis)10,950 4,568 
Acquisitions (1)3,545 3,701 
Current year total capital expenditures, including acquisitions14,495 8,269 
Change in capital accruals633 4,194 
Total cash paid for capital expenditures$15,128 $12,463 
____________________
(1)Excludes $3.9 million for the year ended December 31, 2020, related to non-monetary transactions.


Capital expenditures, excluding acquisitions, for development and production activities increased for the year ended December 31, 2021 compared to 2020, which is in line with the planned increase in costs as result of our well reactivation program.

Cash Flows from Financing Activities

Our financing activities used $22.0 million in of cash for the year ended December 31, 2021, consisting primarily of repayments of borrowings under the 2020 Credit Facility of $20.0 million, finance lease payments of $1.0 million and cash paid for tax obligations on vested stock awards of $0.9 million.

Our financing activities used $39.0 million in cash for the year ended December 31, 2020, consisting primarily of repayments of borrowings under the 2017 Credit Facility of $96.5 million, finance lease payments of $1.2 million and cash paid for tax obligations on vested stock awards of $0.1 million partially offset by proceeds from borrowings of $59.0 million.
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Indebtedness

Credit Facility

On November 30, 2020, the Company entered into the $30 million 2020 Credit Facility with the lenders party thereto and Icahn Agency Services LLC, as administrative agent (the “New Administrative Agent”). The 2020 Credit Facility consisted of a $10 million revolving loan facility and a $20 million term loan facility. During the third quarter of 2021, the 2020 Credit Facility was terminated, as discussed below.

On September 2, 2021, we repaid our $20.0 million term loan in full and terminated all commitments and obligations under the 2020 Credit Facility, between us, as Borrower, IEP Energy Holding LLC, as Lender, and Icahn Agency Services LLC, as Administrative Agent. Our payment to the Lender under the Credit Agreement satisfied all of our term debt and revolving debt obligations. We did not incur any early termination penalties as a result of the repayment of indebtedness or termination of the Credit Agreement. See “Note 11Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt during 2021 and 2020.

Share Repurchase Program

On August 16, 2021, our Board approved the initiation of a share repurchase program authorizing us to purchase up to an aggregate of $25.0 million of our common stock beginning as early as August 16, 2021. We did not repurchase any common stock under the Program during the year ended 2021.

Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2021, our contractual obligations included asset retirement obligations, short and long-term leases and other individually insignificant obligations. Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including surety bonds. The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable. Therefore, no additional liability is reflected for the surety bonds or other instruments.

As of December 31, 2021, we had future contractual payment commitments under various agreements, which are summarized below. The operating leases are not recorded in the accompanying consolidated balance sheets.
 Payments Due by Period
 Total
Less than
1 year
1-3 years3-5 years
More than
5 years
 (In thousands)
Asset retirement obligations (1)$59,368 $17,606 $116 $47 $41,599 
Operating lease167 167 
Finance lease779 351 428 — — 
Total$60,314 $18,124 $544 $47 $41,599 
____________________
(1)Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2021. These estimates and assumptions can be inherently unpredictable and may differ from actual results given the uncertainty of when we may be required to plug and abandon a well or retire an asset. As a result, we may not incur all of the estimated costs for the current asset retirement obligation as depicted above. During the year ended December 31, 2021, plugging and abandonment costs incurred were $2.1 million.

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Valuation Allowance

Upon emergence from bankruptcy and the application of fresh start accounting in 2016, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had significant U.S. federal net operating losses remaining after the attribute reduction caused by the restructuring transactions. As such, the successor Company had significant deferred tax assets to consume upon emergence. We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be fully realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through December 31, 2021.

We continue to closely monitor all available evidence in considering whether to maintain a valuation allowance on our net deferred tax asset. Factors considered include, but are not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, our historical earnings and the prospects of future earnings. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.

In determining whether to maintain the valuation allowance at December 31, 2021, we concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual cumulative negative earnings for the Successor Company period ending December 31, 2021, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, we have not changed our judgment regarding the need for a full valuation allowance against our net deferred tax asset for the period ending December 31, 2021.

See “Note 14Income Taxes” to the accompanying consolidated financial statements for additional discussion of income tax related matters.
53


Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company’s financial statements requires management to make assumptions and prepare estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Estimates are based on historical experience and various other assumptions believed to be reasonable; however, actual results may differ significantly. The Company’s critical accounting policies and additional information on significant estimates are discussed below. See “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies.

Proved Reserves.  Over 96.0% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2021. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control. Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data. The accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2021 and 2020, the Company revised its proved reserves from prior years’ reports by approximately 43.3 MMBoe and (44.8) MMBoe, respectively, due to increases (or decreases) in SEC prices used to value reserves at the end of the applicable period, production performance indicating more (or less) reserves in place, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries among other factors. Estimates of proved reserves are key components of the Company’s financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect the Company’s future depreciation, depletion and impairment expenses.

Impairment of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of oil and natural gas properties and electrical infrastructure costs, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, may not exceed an amount equal to the ceiling limitation. The Company calculates its full cost ceiling limitation using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Company recorded full cost ceiling did not record any impairment for the year ended December 31, 2021 and $218.4 million for the year ended December 31, 2020. See “—Consolidated Results of Operations” for additional discussion of full cost ceiling impairments.

See “—Consolidated Results of Operations” and “Note 9—Impairment” to the Company’s accompanying consolidated financial statements in Item 8 of this report for a discussion of the Company’s impairments.

Asset Retirement Obligations. Asset retirement obligations represent the estimate of fair value of the cost to plug, abandon and remediate the Company’s wells at the end of their productive lives, in accordance with applicable federal and state laws. The Company estimates the fair value of an asset’s retirement obligation in the period in which the liability is incurred (at the time the wells are drilled or acquired). Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. The Company employs a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs. Inherent in the present value calculation are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.

Income Taxes. Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation
54

allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns. As of December 31, 2021, the Company had a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.

New Accounting Pronouncements. For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report.

55



Item 7A. Quantitative and Qualitative Disclosures About Market Risk

General

This discussion provides information about the financial instruments we use to manage commodity prices. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement. Additionally, our exposure to credit risk and interest rate risk is also discussed.

Commodity Price Risk. Our most significant market risk relates to the prices we receive for oil, natural gas and NGLs. Due to the historical price volatility of these commodities, from time to time, depending upon our view of opportunities under the then-prevailing market conditions, we enter into commodity pricing derivative contracts for a portion of our anticipated production volumes for the purpose of reducing the variability of oil and natural gas prices we receive.

We may use a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At December 31, 2021, the Company's open derivative contracts consisted of natural gas and NGL commodity derivative contracts under which we will receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume. These commodity derivative contracts consisted of the following:

NotionalUnitsWeighted Average Fixed Price per Unit
NGL Price Swaps: January 2022 - February 20221,042,000 Gallons$1.20 
Natural Gas Price Swaps: January 2022 - February 2022720,000 MMBtu$4.07 

Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts are recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on a comparison of future prices to the contract price at the period-end.

The following table summarizes derivative activity for the years ended December 31, 2021 and 2020 (in thousands):
Year Ended December 31,
20212020
Loss (gain) on commodity derivative contracts$2,251 $(5,765)
Cash paid (received) on settlements$2,230 $(5,879)

See “Note 6—Derivatives” to the accompanying consolidated financial statements in Item 8 of this report for additional information regarding our commodity derivatives.

Credit Risk. We are exposed to credit risk related to counterparties to our derivative financial contracts. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating. We monitor the credit ratings of our derivative counterparties and consider our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. Historically, derivative contracts have been with multiple counterparties to minimize exposure to any individual counterparty, and in addition our counterparties have been large financial institutions.

We do not require collateral or other security from counterparties to support derivative instruments. We have master netting agreements with our derivative contract counterparties, which allow us to net our derivative assets and liabilities by commodity type with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. Therefore, we are not required to post additional collateral under our commodity derivative contracts.

We are also exposed to credit risk related to the collection of receivables from our joint interest partners for their proportionate share of expenditures made on projects we operate. Historically, our credit losses on joint interest receivables have been immaterial.
56


Interest Rate Risk. We were exposed to interest rate risk under the 2020 Credit Facility. The variable interest rate on our 2020 Credit Facility fluctuated, and exposed us to short-term changes in market interest rates as our interest obligations on this instrument were periodically redetermined based on prevailing market interest rates, primarily LIBOR. The 2020 Credit Facility was terminated during the second half of 2021. See "Note11 Long-Term Debt" to the accompanying consolidated financial statements in Item 8 of this report for further discussion.
57


Item 8.    Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

58


Management’s Report on Internal Control over Financial Reporting

Management of SandRidge Energy, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013) (the COSO criteria). Based on management’s assessment using the COSO criteria, management concluded the Company’s internal control over financial reporting was effective as of December 31, 2021.

 
/s/    GRAYSON PRANIN   
 
/s/    SALAH GAMOUDI     
Grayson Pranin
President, Chief Executive Officer and Chief Operating Officer
 
Salah Gamoudi
Senior Vice President, Chief Financial Officer and Chief Accounting Officer

59

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the stockholders and the Board of Directors of SandRidge Energy, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of SandRidge Energy, Inc. and subsidiaries (the "Company") as of December 31, 2021 and 2020, the related consolidated statements of operations, changes in stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 10, 2022, expressed an unqualified opinion on the Company's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Proved Oil and Natural Gas Properties, Depletion— Refer to Notes 1 and 8 to the consolidated financial statements

Critical Audit Matter Description

The Company’s proved and natural gas properties are amortized using the unit-of-production method. The development of the Company’s oil and natural gas reserve quantities requires management to make significant estimates and assumptions related to rates of production. The Company engages independent petroleum engineers to estimate oil and natural gas reserves using estimates, assumptions, and engineering data. Changes in these assumptions could materially affect the Company’s estimated reserve quantities and the amount of depletion. The proved oil and natural gas properties balance was $1.5 billion, and the associated accumulated depreciation, depletion and impairment was $1.4 billion as December 31, 2021. Depreciation and depletion- oil and natural gas expense was $9.4 million for the year ended December 31, 2021.

Given the significant judgments made by management, performing audit procedures to evaluate the Company’s oil and natural gas reserve quantities including management’s estimates and assumptions related to forecasted rates of production requires a high degree of auditor judgment and an increased extent of effort.



60

How the Critical Audit Matter Was Addressed in the Audit

Our audit procedures to address management’s significant judgments and estimates associated with oil and natural gas reserve quantities included the following, among others:

We tested the operating effectiveness of controls over the Company’s estimation of oil and natural gas reserve quantities.

We evaluated the reasonableness of management’s estimated reserve quantities by performing the following:

Evaluating the experience, qualifications and objectivity of the Company’s independent reserve engineers including the methodologies used to estimate oil and natural gas reserve quantities.

For a sample of proved developed wells, we evaluated the wells expected forecasted production by comparing such the expected decline rate of production in future periods to historical production volumes and decline rates of the well.


/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 10, 2022

We have served as the Company's auditor since 2019.

61

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors of SandRidge Energy, Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of SandRidge Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2021, of the Company and our report dated March 10, 2022 expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 10, 2022
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SandRidge Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
 
December 31,
 20212020
(In thousands)
ASSETS
Current assets
Cash and cash equivalents$137,260 $22,130 
Restricted cash - other 2,264 6,136 
Accounts receivable, net21,505 19,576 
Prepaid expenses626 2,890 
Other current assets80 80 
Total current assets161,735 50,812 
Oil and natural gas properties, using full cost method of accounting
Proved1,454,016 1,463,950 
Unproved12,255 17,964 
Less: accumulated depreciation, depletion and impairment(1,373,217)(1,375,692)
93,054 106,222 
Other property, plant and equipment, net97,791 103,118 
Other assets332 680 
Total assets$352,912 $260,832 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses$45,779 $51,426 
Asset retirement obligations17,606 16,467 
Derivative contracts21  
Other current liabilities627 984 
Total current liabilities64,033 68,877 
Long-term debt 20,000 
Asset retirement obligations41,762 40,701 
Other long-term obligations1,795 3,188 
Total liabilities107,590 132,766 
Commitments and contingencies (Note 13)
Stockholders’ Equity
Common stock, $0.001 par value; 250,000 shares authorized; 36,675 issued and outstanding at December 31, 2021 and 35,928 issued and outstanding at December 31, 2020
37 36 
Warrants88,520 88,520 
Additional paid-in capital1,062,737 1,062,220 
Accumulated deficit(905,972)(1,022,710)
Total stockholders’ equity245,322 128,066 
Total liabilities and stockholders’ equity$352,912 $260,832 

The accompanying notes are an integral part of these consolidated financial statements.
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SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Operations