| Delaware | 20-8084793 | |||||||||||||||||||||||
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||||||||||||||||||
Oklahoma City, Oklahoma | 73104 | |||||||||||||||||||||||
| (Address of principal executive offices) | (Zip Code) | |||||||||||||||||||||||
| (405) 429-5500 | ||||||||||||||||||||||||
| (Registrant’s telephone number, including area code) | ||||||||||||||||||||||||
| Securities registered pursuant to Section 12(b) of the Act: | ||||||||||||||||||||||||
| Title of | Trading Symbol | Name of | ||||||||||||||||||||||
| Common Stock, $0.001 par value | SD | New 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 þ☑
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 þ☑
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 þ ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes þ ☑ 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 filer | ☐ | Smaller 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, 20172021 was approximately $586.9$195.5 million based on the closing price as quoted on the New York Stock Exchange. As of February 15, 2018,March 3, 2022, there were 35,641,90736,696,519 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 20182022 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.
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 | ||||||||
| 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. | ||
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 includes terms commonlyin 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 industry,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 definedseparated 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 “Glossaryreservoir rock to increase permeability and porosity.
IRS. Internal Revenue Service.
Lease. A contract in which the owner of Oilminerals 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 Terms” beginninggas 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 page 23.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
•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 natural gas liquids (“NGL”)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;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;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;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.
6
PART I
Item 1. Business
GENERAL
We are an independent oil and natural gas company, organized in 2006, as a Delaware corporation, with a principal focus on explorationacquisition, development and production activities in the U.S. Mid-Continent andMid-Continent. Prior to February 5, 2021, we held assets in the North Park Basin of Colorado. Our North Park Basin properties were acquired during the fourth quarter of 2015.Colorado, which have been sold in their entirety.
As of December 31, 2017,2021, we had 2,869an interest in 1,442 gross (2,096.8(817.0 net) producing wells, approximately 2,419947 of which we operate, and approximately 931,000551,000 gross (643,000(368,000 net) total acres under lease. As of December 31, 2017,2021, we had twono rigs drilling in the Mid-Continent and two rigs drilling in the North Park Basin.drilling. Total estimated proved reserves as of December 31, 2017,2021, were 177.671.3 MMBoe, of which approximately 70%100% were proved developed.
Our principal executive offices are located at 123 Robert S. Kerr Avenue,1 E. Sheridan Ave, Suite 500, Oklahoma City, Oklahoma 7310273104 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 electronically file such material with, or furnish it to, the Securities and Exchange Commission (“SEC”).SEC. Any materials that we have filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549 or accessed via the SEC’s website address at www.sec.gov.
7
Table of the Mid-Continent area and the North Park Basin of Colorado where we have significant operating experience. Use of our stock as a currency in such acquisitions will be primarily limited to acquisitions that carry a similar or lower multiple to our stock.Contents
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 exploration, development and productionacquisition of oil and natural gas.hydrocarbon resources. The following table presents information concerning our exploration and production activities by geographic area of operationoperations as of December 31, 2017.2021.
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-Continent | 71.3 | 18.5 | 10.6 | 551,000 | 368,000 | $ | 14.4 | ||||||||||||||||||||||||||||
____________________
Estimated Net Proved Reserves (MMBoe) | Daily Production (MBoe/d)(1) | Reserves/ Production (Years)(2) | Gross Acreage | Net Acreage | Capital Expenditures (In millions) (3) | |||||||||||||
| Area | ||||||||||||||||||
| Mid-Continent | 130.6 | 33.6 | 10.6 | 774,830 | 497,465 | $ | 149.9 | |||||||||||
| North Park Basin | 40.2 | 2.9 | 38.0 | 128,490 | 121,712 | 94.7 | ||||||||||||
| Permian Basin | 6.8 | 1.3 | 14.3 | 27,970 | 23,571 | 1.4 | ||||||||||||
| Total | 177.6 | 37.8 | 12.9 | 931,290 | 642,748 | $ | 246.0 | |||||||||||
(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 775,000551,000 gross (497,000(368,000 net) leasehold acres located primarily in Oklahoma and Kansas at December 31, 2017.2021. Associated proved reserves at December 31, 20172021 totaled 130.671.3 MMBoe, 86.6%100.0% of which were proved developed reserves. Our interests in the Mid-Continent as of December 31, 20172021 included 1,7741,442 gross (1,021.3(817.0 net) producing wells with an average working interest of 58%56.7%. We had two rigs operatingThe 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 Mid-Continent as of December 31, 2017, which were drilling horizontal wells. One of the rigs was drilling under the drilling participation agreement described below. As of December 31, 2017,Devonian-aged Woodford Shale formation. The Mississippian formation is approximately 350 to 650 feet in gross thickness across our Mid-Continent properties included an inventory of 64 operated proved undeveloped lateralslease position and has targeted porosity zone(s) ranging between 20 and 150 feet in addition to several hundred undeveloped probable horizontal well locations. During 2017, we drilled a total of 16 horizontal producing wells in this area which included a combination of primarily short reach lateral and extended reach lateral well configurations.
North Park Basin
8
Table of December 31, 2017, our other properties consisted of approximately 28,000 gross (24,000 net) leasehold acres, 1,066 gross (1,046.5 net) producing wells with an average working interest of 98%. Associated proved reserves at December 31, 2017 were 6.8 MMBoe, 100% of which were proved developed reserves. We did not drill any wells in this area during 2017.Contents
Proved Reserves
The estimates of oil, natural gas and NGL reserves in this report are based on reserve reports, which were largely prepared by independent petroleum engineers. To achieve reasonable certainty, the Company’s reservoir engineers relied on 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 petroleum engineers. Such consultation included review of properties, assumptions and any new data available. The Company’s internal reserves estimates and methodologies, as prepared by various Subsurface and Corporate Reserves personnel, were compared to those prepared by independent petroleum engineers to test the reserves estimates and conclusions before the reserves estimates were included in this report. The accuracy of the reserve estimates is dependent on many factors, including the following:
| December 31, | ||||||||
| 2017 | 2016 | 2015 | ||||||
| Cawley, Gillespie & Associates, Inc. | 62.6 | % | 72.0 | % | 77.7 | % | ||
| Ryder Scott Company, L.P. | 29.0 | % | 18.4 | % | 8.5 | % | ||
| Netherland, Sewell & Associates, Inc. | 3.8 | % | 3.6 | % | 3.9 | % | ||
| Total | 95.4 | % | 94.0 | % | 90.1 | % | ||
Existing economic conditions include prices, costs, operating methods and costsgovernment regulations existing at which economic producibility from a reservoir isthe time the reserve estimates are made. SEC prices are used to be determined. In determining the amount ofdetermine proved reserves, the price used must be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, 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.
Over 96% of the proved oil, natural gas and NGL reserves disclosed in this report are based on reserve estimates of proved developed reserves included in thedetermined and prepared by independent reserve report were preparedengineers primarily using decline curve analysis to determine the reserves of individual producing wells. After estimatingA small portion of the proved reserves of each proved developed well, it wasdisclosed in this report were determined that aby internal reserve engineers. To establish reasonable level of certainty exists 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 can be expecteddata;
•estimates regarding the amount and timing of future costs, which could vary considerably from close offset undeveloped wellsactual 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.
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Key reserve information is reviewed and approved at least annually by the Company’s Chief Executive Officer and Chief Financial Officer.
SandRidge’s reserve engineers and the Reservoir Engineering Supervisor works closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the audit committee. 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 field.
table below.
| December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Cawley, Gillespie & Associates, Inc. | 96.2 | % | 73.6 | % | |||||||||||||
| Ryder Scott Company, L.P. (1) | — | % | 17.9 | % | |||||||||||||
| Total | 96.2 | % | 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 produced as a result of therecovered through further processing of a portion of our natural gas production stream. At December 31, 2017,2021, NGLs comprised approximately 19%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 separate 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, 20172021 and 2020 approximately 96% and over 90%, 2016 and 2015, the substantial majorityrespectively, of which were prepared by independent petroleumreserve engineers. The PV-10 values shown in the table below are not intended to represent the current market value of estimated proved reserves as of the dates shown. The reserve reports were based on the Company’sour drilling schedule at the time year endyear-end reserve reportsestimates were prepared. Reserves for 2017 and 2016 include our proportionate share
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, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| 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 | |||||||||||||
| December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Estimated Proved Reserves(1) | |||||||||||
| Developed | |||||||||||
| Oil (MMBbls) | 25.9 | 25.9 | 48.6 | ||||||||
| NGL (MMBbls) | 29.9 | 29.3 | 51.1 | ||||||||
| Natural gas (Bcf) | 408.0 | 393.0 | 964.6 | ||||||||
| Total proved developed (MMBoe) | 123.8 | 120.7 | 260.5 | ||||||||
| Undeveloped | |||||||||||
| Oil (MMBbls) | 35.9 | 27.0 | 29.3 | ||||||||
| NGL (MMBbls) | 4.4 | 4.2 | 9.9 | ||||||||
| Natural gas (Bcf) | 80.9 | 71.8 | 149.2 | ||||||||
| Total proved undeveloped (MMBoe) | 53.8 | 43.2 | 64.1 | ||||||||
| Total Proved | |||||||||||
| Oil (MMBbls) | 61.8 | 52.9 | 77.9 | ||||||||
| NGL (MMBbls) | 34.3 | 33.5 | 61.0 | ||||||||
| Natural gas (Bcf) | 488.9 | 464.8 | 1,113.8 | ||||||||
| Total proved (MMBoe)(2) | 177.6 | 163.9 | 324.6 | ||||||||
Standardized Measure of Discounted Net Cash Flows (in millions)(2)(3) | $ | 749.3 | $ | 438.4 | $ | 1,315.0 | |||||
| PV-10 (in millions)(4) | $ | 749.3 | $ | 438.4 | $ | 1,314.6 | |||||
| Index prices (a) | Weighted average wellhead prices (b) | ||||||||||||||||||
| Oil (per Bbl) | Natural gas (per Mcf) | Oil (per Bbl) | NGL (per Bbl) | Natural gas (per Mcf) | |||||||||||||||
| December 31, 2017 | $ | 51.34 | $ | 2.98 | $ | 48.47 | $ | 20.28 | $ | 1.90 | |||||||||
| December 31, 2016 | $ | 42.75 | $ | 2.48 | $ | 38.59 | $ | 10.99 | $ | 1.56 | |||||||||
| December 31, 2015 | $ | 50.28 | $ | 2.59 | $ | 45.29 | $ | 12.68 | $ | 1.87 | |||||||||
Estimated Proved Reserves (MMBoe) | Standardized Measure (In millions) | |||||
| 12/31/2015 | 19.1 | $ | 224.6 | |||
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 | |||||||||||||||||||
____________________
(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 noncontrolling interests.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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| December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| (In millions) | |||||||||||
| Standardized Measure of Discounted Net Cash Flows | $ | 749.3 | $ | 438.4 | $ | 1,314.6 | |||||
| Present value of future income tax discounted at 10% | — | — | 0.4 | ||||||||
| PV-10 | $ | 749.3 | $ | 438.4 | $ | 1,315.0 | |||||
The following table provides a reconciliation of our Standardized Measure to PV-10:
| December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| (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 in the Mid-Continent, primarily the Mississippian formation, increased from 127.833.4 MMBoe at December 31, 20162020 to 130.671.3 MMBoe at December 31, 2017. Net2021, primarily as a result of production, reserves increased by 18.4positive revisions of 27.3 MMBoe primarily dueassociated 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 8.4a well reactivation program, and purchases of 1.4 MMBoe of extensions from successful drilling in our NW STACK playproved reserves. The Company also recorded 2021 production totaling 6.7 MMBoe and 9.8a decrease of 1.4 MMBoe from revisions of prior estimates primarily due to significantly higher commodity prices in 2017 and minor revisions dueattributable to well performance. These increases were partially offset by 1.9 MMBoe of asset sales.shut-ins, sales and other revisions.
Proved Reserves - North Park Basin.Our North Park Basin Niobrara proved Proved reserves were acquired in December 2015 and increased from 30.2 MMBoe at December 31, 2016 to 40.2 MMBoe at December 31, 2017, primarily due to reserve extensions from horizontal drilling. The acquisition of these reserves in 2015 provided an important proved reserve addition to our asset base. Niobrara proved developed reserves were booked based on 29 horizontal producing wells across the play. Reservoir characteristics of the Niobrara in the North Park Basin are similardecreased from 3.5 MMBoe at December 31, 2020 to those0 MMBoe at December 31, 2021, as the result of the Niobrara in the DJ Basin to the eastsale of North Park, with the Niobrara consisting3.4 MMBoe of multiple stratigraphic benches. In North Park Basin, production performance and reservoir data gathered from the producing wells confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. Using the performance of the proved developed producing wells, proved undeveloped reserves were booked across 35 sections of the proved development area at a density of up to eight wells per section, considering only estimated recovery from the two deepest stratigraphic benches. Delineation drilling to determine effective spacing for optimal reserve recovery is ongoing, although early results and well density in the DJ Basin Niobrara indicates the potential for booking more than eight wells per section.
Proved Undeveloped Reserves. The following table summarizes activity associated with proved undeveloped reserves during the periods presented:
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Reserves converted from proved undeveloped to proved developed (MMBoe) | 1.1 | 6.8 | 15.8 | ||||||||
| Drilling capital expended to convert proved undeveloped reserves to proved developed reserves (in millions) | $ | 21.0 | $ | 64.5 | $ | 117.7 | |||||
For additional information regarding changes in proved reserves during each of the threetwo years ended December 31, 2017, 20162021 and 20152020 see “Note 22—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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Oil (MBbls) | NGL (MBbls) | Natural Gas (MMcf) | Total (MBoe) | ||||||||
| Year Ended December 31, 2017 | |||||||||||
| Mississippi Lime Horizontal | 2,382 | 2,995 | 38,834 | 11,849 | |||||||
| Niobrara | 673 | — | — | 673 | |||||||
| Year Ended December 31, 2016 | |||||||||||
| Mississippi Lime Horizontal | 5,029 | 4,357 | 56,894 | 18,868 | |||||||
| Niobrara | 500 | — | — | 500 | |||||||
| Year Ended December 31, 2015 | |||||||||||
| Mississippi Lime Horizontal | 8,041 | 4,785 | 77,542 | 25,750 | |||||||
Production and Price History
The following tables set forthtable 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, | |||||||||||||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||||||||||||
| Successor | Predecessor | Predecessor | |||||||||||||||||||||||||||||||
Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | ||||||||||||||||||||||||||||||
| 2017 | 2016 | 2016 | 2015 | ||||||||||||||||||||||||||||||
| Production data (in thousands) | Production data (in thousands) | ||||||||||||||||||||||||||||||||
| Oil (MBbls) | 4,157 | 1,214 | 4,315 | 9,600 | Oil (MBbls) | 957 | 2,084 | ||||||||||||||||||||||||||
| NGL (MBbls) | 3,376 | 999 | 3,358 | 5,044 | NGL (MBbls) | 2,267 | 2,694 | ||||||||||||||||||||||||||
| Natural gas (MMcf) | 44,237 | 12,771 | 44,124 | 92,105 | Natural gas (MMcf) | 21,417 | 23,552 | ||||||||||||||||||||||||||
| Total volumes (MBoe) | 14,906 | 4,342 | 15,027 | 29,995 | Total volumes (MBoe) | 6,793 | 8,703 | ||||||||||||||||||||||||||
| Average daily total volumes (MBoe/d) | 40.8 | 47.7 | 54.6 | 82.2 | Average daily total volumes (MBoe/d) | 18.6 | 23.8 | ||||||||||||||||||||||||||
| Average prices—as reported(1) | |||||||||||||||||||||||||||||||||
| Average prices—as reported (1) | Average prices—as reported (1) | ||||||||||||||||||||||||||||||||
| Oil (per Bbl) | $ | 48.72 | $ | 47.03 | $ | 36.85 | $ | 45.83 | Oil (per Bbl) | $ | 65.10 | $ | 35.33 | ||||||||||||||||||||
| NGL (per Bbl) | $ | 18.16 | $ | 14.77 | $ | 12.67 | $ | 14.36 | NGL (per Bbl) | $ | 22.42 | $ | 6.67 | ||||||||||||||||||||
| Natural gas (per Mcf) | $ | 2.09 | $ | 2.07 | $ | 1.78 | $ | 2.12 | Natural gas (per Mcf) | $ | 2.60 | $ | 0.97 | ||||||||||||||||||||
| Total (per Boe) | $ | 23.90 | $ | 22.64 | $ | 18.63 | $ | 23.59 | Total (per Boe) | $ | 24.86 | $ | 13.15 | ||||||||||||||||||||
| Expenses per Boe | Expenses per Boe | ||||||||||||||||||||||||||||||||
| Total lease operating expenses(2)(3) | $ | 6.64 | $ | 5.69 | $ | 8.49 | $ | 10.06 | |||||||||||||||||||||||||
| Production costs (2) | Production costs (2) | $ | 5.30 | $ | 4.99 | ||||||||||||||||||||||||||||
__________________
(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 sets forthpresents the number of productive wells in which the Companywe owned a working interest at December 31, 2017.2021. We operate substantially all of our net wells. Productive wells consist of wells that are currently producing wells and wells capable of producing, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries.hydrocarbons. Gross wells are the total number of producing wells in which the Company haswe have a working interest and net wells are the sum of the fractional working interests owned in gross wells. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.
| Oil | Natural Gas | Total | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Geographic Area | |||||||||||||||||||||||||||||||||||
| Mid-Continent | 1,121 | 615 | 321 | 202 | 1,442 | 817 | |||||||||||||||||||||||||||||
| Oil | Natural Gas | Total | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Area | |||||||||||||||||
| Mid-Continent | 1,536 | 916.2 | 238 | 105.1 | 1,774 | 1,021.3 | |||||||||||
| North Park Basin | 29 | 29.0 | — | — | 29 | 29.0 | |||||||||||
| Permian Basin | 1,066 | 1,046.5 | — | — | 1,066 | 1,046.5 | |||||||||||
| Total | 2,631 | 1,991.7 | 238 | 105.1 | 2,869 | 2,096.8 | |||||||||||
Drilling Activity
| 2017 | 2016 | 2015 | |||||||||||||||||||||||||||||||||
| Gross | Percent | Net | Percent | Gross | Percent | Net | Percent | Gross | Percent | Net | Percent | ||||||||||||||||||||||||
| Completed Wells | |||||||||||||||||||||||||||||||||||
| Development | |||||||||||||||||||||||||||||||||||
| Productive | 22 | 100.0 | % | 16.4 | 100.0 | % | 32 | 100.0 | % | 27.0 | 100.0 | % | 167 | 100.0 | % | 117.0 | 100.0 | % | |||||||||||||||||
| Dry | — | — | % | — | — | % | — | — | % | — | — | % | — | — | % | — | — | % | |||||||||||||||||
| Total | 22 | 100.0 | % | 16.4 | 100.0 | % | 32 | 100.0 | % | 27.0 | 100.0 | % | 167 | 100.0 | % | 117.0 | 100.0 | % | |||||||||||||||||
| Exploratory | |||||||||||||||||||||||||||||||||||
| Productive | 1 | 100.0 | % | 1.0 | 100.0 | % | — | — | % | — | — | % | 9 | 100.0 | % | 7.0 | 100.0 | % | |||||||||||||||||
| Dry | — | — | % | — | — | % | — | — | % | — | — | % | — | — | % | — | — | % | |||||||||||||||||
| Total | 1 | 100.0 | % | 1.0 | 100.0 | % | — | — | % | — | — | % | 9 | 100.0 | % | 7.0 | 100.0 | % | |||||||||||||||||
| Total | |||||||||||||||||||||||||||||||||||
| Productive | 23 | 100.0 | % | 17.4 | 100.0 | % | 32 | 100.0 | % | 27.0 | 100.0 | % | 176 | 100.0 | % | 124.0 | 100.0 | % | |||||||||||||||||
| Dry | — | — | % | — | — | % | — | — | % | — | — | % | — | — | % | — | — | % | |||||||||||||||||
| Total | 23 | 100.0 | % | 17.4 | 100.0 | % | 32 | 100.0 | % | 27.0 | 100.0 | % | 176 | 100.0 | % | 124.0 | 100.0 | % | |||||||||||||||||
Developed and Undeveloped Acreage
The following table sets forthpresents information regarding the Company’sour developed and undeveloped acreage at December 31, 2017:2021. Prior to February 5, 2021, we held assets in the North Park Basin, which have been sold in their entirety.
| Developed Acreage | Undeveloped Acreage | ||||||||||||||||||||||
| Gross | Net | Gross | Net | ||||||||||||||||||||
| Geographic Area | |||||||||||||||||||||||
| Mid-Continent | 465,449 | 338,684 | 85,583 | 29,802 | |||||||||||||||||||
| Developed Acreage | Undeveloped Acreage | ||||||||||
| Gross | Net | Gross | Net | ||||||||
| Area | |||||||||||
| Mid-Continent | 597,173 | 390,650 | 177,657 | 106,814 | |||||||
| North Park Basin | 13,828 | 13,874 | 114,663 | 107,838 | |||||||
| Permian Basin | 17,743 | 14,755 | 10,226 | 8,817 | |||||||
| Total | 628,744 | 419,279 | 302,546 | 223,469 | |||||||
13
establish production from the leasehold acreage is established prior to such date, inexpiration, which eventwould keep the lease will remain in effectfrom expiring until production has ceased.
As of December 31, 2017,2021, the gross and net acres subject to leases in the undeveloped acreage summarized in the above table are set to expire as follows:
| Acres Expiring | |||||||||||
| Gross | Net | ||||||||||
| Twelve Months Ending | |||||||||||
| December 31, 2022 | 2,120 | 1,622 | |||||||||
| December 31, 2023 | — | — | |||||||||
| December 31, 2024 | 566 | 339 | |||||||||
| December 31, 2025 and later | — | — | |||||||||
| Other (1) | 82,897 | 27,841 | |||||||||
| Total | 85,583 | 29,802 | |||||||||
____________________
| Acres Expiring | |||||
| Gross | Net | ||||
| Twelve Months Ending | |||||
| December 31, 2018 | 53,891 | 36,804 | |||
| December 31, 2019 | 42,698 | 31,402 | |||
| December 31, 2020 | 27,324 | 18,811 | |||
| December 31, 2021 and later | 2,550 | 1,023 | |||
| Lease in Suspense(1) | 30,932 | 30,932 | |||
| Other(2) | 145,151 | 104,497 | |||
| Total | 302,546 | 223,469 | |||
Marketing and Customers
We sell our oil, natural gas and NGLs to a variety of customers, including utilities, oil and natural gas companies and trading and energy marketing companies. We had two customers that each individually accounted for more than 10% of our total revenue during the 20172021 period. See “Note 3—1—Summary of Significant Accounting Policies” to the accompanyingconsolidated financial statements in Item 8 of this report for additional information on our major customers. The number of readily available purchasers forand markets in the areas where we sell our production makes it unlikelyreduces the risk that the loss of a single downstream customer in the areas in which we sell our production 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 an initiala preliminary review of the title to our properties. Prior to commencing drilling operations on thoseour properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We aredefects, typically responsible for curing any title defects at our expense. In addition, prior to completing an acquisition of producing oil and natural gas leases,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
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.
14
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 userspurchasers utilize natural gas storage facilities and purchaseacquire 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, can delay the installation of production facilities, and can 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 exploration, development and production 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 U.S. Environmental Protection Agency (“EPA”)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. WeFurther, 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.
15
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 the Companyus 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)operators or third parties whose waste was commingled with ours), to investigate and clean up contaminated property, to perform remedialcorrective 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 “responsible persons”“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. DespiteAlthough petroleum, natural gas and natural gas liquids are excluded from the definition of "hazardous substance" under CERCLA, despite this so-called “petroleum"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. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary, and complete any revisions to the applicable RCRA regulations no later than July 15, 2021. 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. In addition, in the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that are subject to regulation under the RCRA if they have hazardous characteristics.
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 StandardStandards for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare. The EPA was required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017, but missed the deadline. Subsequently, inIn 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. States haveIn November 2018, the opportunity to submit new air quality monitoring to EPA prior to EPA finalizing anyissued final rules implementing the non-attainment area designations. While the EPA has preliminarily determined that all counties in which we operate are in attainment with the new2015 ozone standard, these determinations may be revised in the future. WithOn 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 loweringhas announced that it intends to issue a proposed rule reconsidering its decision to retain the ground-level2015 ozone standard certain states may be required to implement more stringent regulations, whichby fall 2022 and a final rule by the end of 2023.Further reductions in the ozone National Ambient Air Quality Standards could apply toaffect our operations and result in the need to install new emissions controls, longer permitting timelines and significant increases in our capital or operating expenditures. In addition, 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, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. Compliance with these and otherany 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 federalFederal 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 attemptsattempted to clarify the federal jurisdictional reach over waters of the United States. The 2015 rule was previously stayed nationwide to determine whether federal district or appellate courts had jurisdiction to hear cases inStates (“WOTUS”) under Section 404 of the matter.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 definingredefining the CWA’s jurisdiction. Recently,term WOTUS as used in January 2018,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. SupremeDistrict Court issued a decision finding that jurisdiction to hear challenges tofor the 2015 Rule resides withDistrict of Arizona vacated and remanded the federal district courts; consequently, the previously-filed district court cases will be allowed to proceed. Following the Supreme Court’s decision, theNavigable Waters Protection Rule. On December 7, 2021, EPA and the Corps issued a finalproposed rule to revise the definition of WOTUS, which is expected to be finalized in January 2018 staying implementationlate 2022 or early 2023. The future regulations concerning the definition of the 2015 rule for two years. As aWOTUS may result in an expansion of these recent developments, future implementation of the June 2015 rule is uncertain. To the extent this rule or a revised rule expands 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 any expansion activities.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. Additionally, someSome states have considered laws mandating the recycling of flowback and produced water.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 recentpast 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, onin February 16, 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 operatedSandRidge-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. OnIn March 7, 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 recent 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 a task forcethe 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.Rates (the "Order"). The Order identified five areas of heightened seismic concern inwithin Harper and Sumner Counties and created a timeframe over whichmandated that, within 100 days of the maximum ofOrder’s issuance, operators must limit saltwater injection volumes to no more than 8,000 barrels per day for any well located in one of saltwater injection daily into each well.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 released in March 2015.Order. While no additional regulatory actions werehave been taken in Kansas with respect to induced seismicity concerns insince 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
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Significant Deterioration (“PSD”) construction and Title V operating permit reviewsrequirements for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria pollutant emission.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 established by the states. This ruleGHG emissions could adversely affect our operations and restrict or delay itsour 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. More recently, in
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”). However, over the past yearOn April 18, 2017, the EPA has taken several stepsannounced its intention to delay implementationreconsider certain aspects of those regulations, and in June 2017, the EPA proposed a two-year stay of certain requirements of the Quad Oa standards,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 agencyEnvironment 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 a rulemaking in June 2017rule to stayrevise the requirements for a period of two yearsQuad Oa regulations that, if finalized, would require methane emissions reductions and revisit implementation of Quad Oa in its entirety. Thea fugitive emissions monitoring and repair program. EPA has not yet publishedalso announced its intention to issue a final rule but, as a result ofsupplemental proposal in 2022 that may expand on or modify the 2021 proposal in response to public input. It is possible that these developments,rules and future implementation of the 2016 standards is uncertain at this time. 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 publicfederal lands that are substantially similar to the EPA Quad Oa requirements. However, onin 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. While, asFurther, 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 developments, future implementation ofdecisions, the EPA1979 regulations concerning venting, flaring and BLM methane ruleslost production on federal land have been reinstated. The Biden Administration is uncertain,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 future federal GHG regulations of the oil and gas industry remain a possibility.in this area. Moreover, several states including Colorado, where we operate,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. Compliance with these rules could require us to purchase pollutionWe have the necessary equipment (pollution control equipment and optical gas imaging equipment for LDAR inspections,inspections) and to hire additional personnel trained to assist with inspection and reporting requirements.requirements to maintain compliance with these rules.
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 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. Moreover, inIn June 2017, President Trump stated that the United States announced it would withdraw from the Paris Agreement, but may enter into a future international agreement relatedwhich 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 GHGs. In August 2017, the U.S. State Department officially informed the United Nationsprinciples of the intentParis Agreement in their effectuation of policy and regulations. It is not possible at this time to predict how or when the United States to withdraw frommight impose restrictions on GHGs as a result of the Paris Agreement. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. 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 us to incur additional costsexpenditures 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.activities or increase the costs of such funding. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time.
Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation.
Endangered or Threatened Species
The federal Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats without first obtaining an incidental take permit and implementing mitigation measures. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act and to bald and golden eagles under the Bald and Golden Eagle Protection Act. While compliance with the ESA has not had an adverse effect on our exploration, development and production operations in areas where threatened or endangered species or their habitat are known to exist, it may require us to incur increased costs to implement mitigation or protective measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. In addition, certain of our federal and state leases may contain stipulations that require us to take measures to safeguard certain species, including the sage grouse, and their habitats known to be located within the area of the lease. Although the U.S. Fish and Wildlife Service (“USFWS”) declined to list the sage grouse under the ESAspecies.
Further, in 2015 and subsequently developed a conservation plan to protect existing habit, some environmental groups have continued to raise concerns about sufficient protections for the sage grouse population. In addition, the U.S. Department of Interior (“DOI”) announced in August 2017 that it would revise the existing sage grouse conservation plan that, amongst other things, shifts the focus of protective measures away from potential habitat areas to specific target populations of the sage grouse. Several environmental groups have already announced opposition to DOI’s proposed revisions to sage grouse conservation plan, and it is possible that these groups could pursue new litigation in the future to reconsider listing the sage grouse under the ESA. If endangered or otherwise protected species are located in areas where we wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. On February 11, 2016, the U.S. Fish and Wildlife ServiceUSFWS published a final policy which alters how it identifies critical habitats for endangered and threatened species. AIn 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, designation could resultremoval 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 further material restrictionsDecember 2020 defining the term “habitat” for purposes of making critical habitat designations under the ESA. In general, these rules were designed to federalalleviate some of the burdens of the ESA and private land usestreamline its implementation, but the prospect of new species listings and could delay or prohibit land access or development. Moreover, as a result of a settlement approved bycritical 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 U.S. District Court forEnvironment and Restoring Science to Tackle the District of Columbia in 2011,Climate Crisis. On October 27, 2021, the USFWS was requiredissued a proposal to consider listing numerous species as endangered underrescind the ESA byDecember 2020 ruling, and the endUSFWS may finalize the rescission of the agency’s 2017 fiscal year. The agency has not yet completed this process. For example, we operaterule in several areas in proximity to sage grouse habitat and we are prohibited from performing operations in those areas during certain hours from March to mid-July of each year.2022.
The designation of previously unprotected species as threatened or endangered in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
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 thatus to maintain information be maintained concerning hazardous materials used or produced in our operations and thatto provide this information be provided to employees.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 above certain threshold quantities 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 CAA finalthe Quad Oa regulations in 2012 and additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry;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 unlikely.uncertain. At the state level, some states, including Oklahoma and Colorado,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 governmentgovernments 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 serve on industry association committees 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. There haveWe are not beenaware 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. These types of regulationlevels 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 also 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 Oklahoma and TexasOklahoma 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 up to $1,238,271one 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 up to $1,116,156one 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. Today,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, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress willmight not continue indefinitely into the future nor can wefuture. 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 Price Controlsand 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 up to $1,156,953one 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, 2017, the Company2021, we had 476101 full-time employees, including 67 geologists, geophysicists, petroleum engineers, technicians, land85 field employees and regulatory professionals. Of our 476 employees, 269 were located at the Company’s headquarters in Oklahoma City, Oklahoma at 16 corporate employees. At December 31, 2017,2020, we had 114 full-time employees, including 98 field employees and the remaining employees worked16 corporate employees.
Health, Safety and Environment
Our people are a key driver to our success in our various field officesHealth, Safety and drilling sites.
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 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.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 can fluctuate widely due to a number of factors that are beyond our control. Declines in oil, natural gas or NGL prices could 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 abilityamount of other companies to complete and commission liquefied natural gas export facilities inexports from the U.S.;
•U.S. and worldwide political and economic conditions;conditions, including armed conflict and related sanctions;
•the level of global and U.S. inventories;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; and
•the price and availability of alternative fuels.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 20132017 through December 2017,2021, the highest month end NYMEX settled price was $107.65fluctuated between a high of $85.64 per Bbl and the lowest was $33.62a low of $(36.98) per Bbl. For natural gas, from January 20132017 through December 2017,2021, the highest month endmonth-end NYMEX settled price was $5.56fluctuated between a high of $23.86 per MMBtu and the lowest was $1.71a 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; and
•market and midstream limitations for oil, natural gas and NGLs.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.
Our ability to drill and develop these locationswells 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 the numerous potential wellcertain locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any otherof our potential locations. For example, our North Park Basin assets are in the delineation phase of the development cycle and may require significant investment over the next several years, including the construction of midstream and pipeline takeaway infrastructure, as we progress toward full field development with more activity and an expanded development footprint. We may not be able to raise the substantial amount of capital necessary to fully realize our North Park Basin assets.
Our acreage not contained within federal units 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, and our acreage committed to federal units must be drilled pursuant to the federal unit timelines provided within the unit agreements.production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial leaseadditional 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 that are not federal units 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. Acreage committed to federal units must be drilled pursuant to the federal unit timelines provided within the unit agreements, typically requiring two unit wells within the first 5 years and two more wells within the next five years. At the end of the second five-year term the unit begins to reduce in size to designated participating areas within the Federal Units. Unless we increase our currentbegin drilling, program, 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 so develop such acreage.
Our development operations or ability to acquire oil and exploration operationsgas properties and reserves require substantial capital. WeOutside 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 aour ability to offset the natural decline in our oil, natural gas and NGL reserves.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 exploration,acquisition, development production and acquisitionproduction 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 and from the sale of equity and debt securities and cash generated by operations.sales. In particular, cash flow from operations was $181.2were $110.3 million and $36.2 million for the yearyears ended December 31, 2017. Cash flow from operations was $65.6 million for the Successor 2016 Period, cash used in operations was $112.1 million for the Predecessor 2016 Period,2021 and cash flow from operations was $373.5 million, for the year ended December 31, 2015. 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 drilling and 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 seeknot be able to develop, find or acquire additional financing.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 exploration and development of its 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 lowercost of cost or market value of unevaluatedunproved properties. The full cost ceiling is evaluated at the end of each quarter using the most recent 12-month averageSEC prices, for oil and natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges.hedges, if any. The Successor Company did not incurrecognize any full cost ceiling impairment charges for the year ended December 31, 2017. During the Successor 2016 Period, the Predecessor 2016 Period and the year ended December 31, 2015, we2021. The Company incurred full cost ceiling impairment charges of $319.1$218.4 million $657.4 million and $4.5 billion, respectively.for the year ended December 31, 2020. Cumulative full cost ceiling impairment from the Emergence dateDate through December 31, 2016 and 20172021 totaled $319.1 million, respectively.$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 its 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. Further, the borrowing base under our credit facility is calculated by reference to the value of our oil and natural gas reserves, as determined by the lenders under the credit facility, and declines in the value of such reserves as a result of sustained low commodity prices could reduce the amount available to be borrowed under our credit facility if prices decline from current levels.
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. We depend on the services of our senior management and technical personnel, including our director William M. Griffin, Jr., who is serving as our Interim President and Chief Executive Officer, and our Senior Vice President and Chief Accounting Officer Michael A. Johnson, who will be serving as our Interim Chief Financial Officer. The market for qualified personnel has historically been, and we expect that it will continue to be, intensely competitive. We cannot assure you 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.
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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.
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 its 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. During 2017, we completed a total of 23 gross wells, none of which were identified as dry wells. If we drill additional wells that we identify as dry wells in our current and future prospects, our drilling success rate may decline and materially harm our business.
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 have recently experiencedmay experience drought conditions.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.
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.
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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 exploration and 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 exploration and 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 our drilling operations.
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 exploration,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 exploration and productionoperations 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, or 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 exploration and production 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 utilizehave 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: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 waterwaste-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 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 to the U.S. Circuit Court of Appeals for the Tenth Circuit. However, following issuance ofand after various appeals and a presidential executive order directing it 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 repealingrescinding the 2015 hydraulic fracturing 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 unlikely.uncertain. In addition, certain states, including Oklahoma, and Colorado, 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 the Company.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 the Company produces.we produce.
The EPA haspreviously 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, over the past year the EPA has taken several steps to delay implementation of the Quad Oa standards, and thestandards. The agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and revisitin 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 Quad Oa in its entirety. Thea fugitive emissions monitoring and repair program. EPA has not yet publishedalso announced its intention to issue a final rule but, as a result ofsupplemental proposal in 2022 that may expand on or modify the 2021 proposal in response to public input. It is possible that these developments, future implementation of the 2016 standards is uncertain at this time.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. Moreover, several states, including Colorado, where we operate,We have already adopted rules requiring operators of both new and existing sources to develop and implement LDAR program and install devices on certainthe necessary equipment to capture 95% of methane emissions.
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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. Moreover, inIn June 2017, President Trump statedannounced that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. In August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw fromwhich became effective November 4, 2020. On January 20, 2021, President Joe Biden rejoined the Paris Agreement. The United States’ adherence to the exit process is uncertain and/or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
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 itsour 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 explorationdevelopment 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 and sequestration of the CO2 is an emerging technology. While the technology to capture CO2 from terrorist activities or armed conflict could harm our business.
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, 2017,2021, 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.
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.
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 exploration,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.
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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 Emergenceoperations 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 Bankruptcy
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 financial conditionCOVID-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, reflectedliquidity 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 historical financial statements.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 (as defined in Part IV. Note 1 - Voluntary Reorganization under Chapter 11 Proceedings) to purchase approximately 6.67.0 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, 3.01.0 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.
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
Item 4. Mine Safety Disclosures
Not applicable.
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PART II
| Successor Company | High | Low | |||||
| 2017 | |||||||
| Fourth Quarter | $ | 21.50 | $ | 14.65 | |||
| Third Quarter | $ | 20.62 | $ | 16.63 | |||
| Second Quarter | $ | 20.72 | $ | 15.03 | |||
| First Quarter | $ | 23.96 | $ | 16.80 | |||
| 2016 | |||||||
| Fourth Quarter (from October 4, 2016 through December 31, 2016) | $ | 26.85 | $ | 15.75 | |||
| Predecessor Company | |||||||
| Fourth Quarter (through October 3, 2016) | $ | 0.02 | $ | 0.01 | |||
| Third Quarter | $ | 0.06 | $ | — | |||
| Second Quarter | $ | 0.11 | $ | 0.01 | |||
| First Quarter | $ | 0.20 | $ | 0.03 | |||
On February 15, 2018,25, 2022, there were 287330 record holders of the Company’s common stock.
Issuer Purchases of our business, including exploration, development and production activities. In addition, the terms of the Successor Company’s indebtedness restrict our ability to pay dividends to our common stock holders. If our dividend policy were to change in the future, our ability to pay dividends would be subject to these restrictions and the Company’s then-existing conditions, including results of operations, financial condition, contractual obligations, capital requirements, business prospects and other factors deemed relevant by the Successor Company’s board of directors. See further discussion of the risks and uncertainties surrounding the payment of dividends in “Risk Factors” in Item 1A of this report.
None.
Item 6. [Reserved].
41
| Total Number of Shares Purchased(1) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Program | Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (In millions) | ||||||||
| Period | |||||||||||
| October 1, 2017 — October 31, 2017 | 153,408 | $ | 19.10 | N/A | N/A | ||||||
| November 1, 2017 — November 30, 2017 | — | $ | — | N/A | N/A | ||||||
| December 1, 2017 — December 31, 2017 | 1,611 | $ | 21.07 | N/A | N/A | ||||||
| Total | 155,019 | — | |||||||||
| Successor | Predecessor | |||||||||||||||||||||||
| Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | |||||||||||||||||||||
| 2017 | 2016 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||||||
Statement of Operations Data (in thousands, except per share data) | ||||||||||||||||||||||||
| Revenues | $ | 357,299 | $ | 98,456 | $ | 293,809 | $ | 768,709 | $ | 1,558,758 | $ | 1,983,388 | ||||||||||||
| Total operating expenses(1) | 317,668 | 434,801 | 1,200,012 | 5,411,387 | 968,534 | 2,152,389 | ||||||||||||||||||
| Income (loss) from operations | 39,631 | (336,345 | ) | (906,203 | ) | (4,642,678 | ) | 590,224 | (169,001 | ) | ||||||||||||||
| Other (expense) income | ||||||||||||||||||||||||
| Interest expense | (3,868 | ) | (372 | ) | (126,099 | ) | (321,421 | ) | (244,109 | ) | (270,234 | ) | ||||||||||||
| Gain (loss) on extinguishment of debt | — | — | 41,179 | 641,131 | — | (82,005 | ) | |||||||||||||||||
| Reorganization items | — | — | 2,430,599 | — | — | — | ||||||||||||||||||
| Other income, net | 2,550 | 2,744 | 1,332 | 2,040 | 3,490 | 12,445 | ||||||||||||||||||
| Total other (expense) income | (1,318 | ) | 2,372 | 2,347,011 | 321,750 | (240,619 | ) | (339,794 | ) | |||||||||||||||
| Income (loss) before income taxes | 38,313 | (333,973 | ) | 1,440,808 | (4,320,928 | ) | 349,605 | (508,795 | ) | |||||||||||||||
| Income tax (benefit) expense | (8,749 | ) | 9 | 11 | 123 | (2,293 | ) | 5,684 | ||||||||||||||||
| Net income (loss) | 47,062 | (333,982 | ) | 1,440,797 | (4,321,051 | ) | 351,898 | (514,479 | ) | |||||||||||||||
| Less: net (loss) income attributable to noncontrolling interest | — | — | — | (623,506 | ) | 98,613 | 39,410 | |||||||||||||||||
| Net income (loss)attributable to SandRidge Energy, Inc. | 47,062 | (333,982 | ) | 1,440,797 | (3,697,545 | ) | 253,285 | (553,889 | ) | |||||||||||||||
| Preferred stock dividends | — | — | 16,321 | 37,950 | 50,025 | 55,525 | ||||||||||||||||||
| Income available (loss applicable) to SandRidge Energy, Inc. common stockholders | $ | 47,062 | $ | (333,982 | ) | $ | 1,424,476 | $ | (3,735,495 | ) | $ | 203,260 | $ | (609,414 | ) | |||||||||
| Earnings (loss) per share | ||||||||||||||||||||||||
| Basic | $ | 1.45 | $ | (17.61 | ) | $ | 2.01 | $ | (7.16 | ) | $ | 0.42 | $ | (1.27 | ) | |||||||||
| Diluted | $ | 1.44 | $ | (17.61 | ) | $ | 2.01 | $ | (7.16 | ) | $ | 0.42 | $ | (1.27 | ) | |||||||||
| Successor | Predecessor | |||||||||||||||||||
| As of December 31, | As of December 31, | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
Balance Sheet Data (in thousands) | ||||||||||||||||||||
| Cash and cash equivalents | $ | 99,143 | $ | 121,231 | $ | 435,588 | $ | 181,253 | $ | 814,663 | ||||||||||
| Property, plant and equipment, net | $ | 923,240 | $ | 817,932 | $ | 2,234,702 | $ | 6,215,057 | $ | 6,307,675 | ||||||||||
| Total assets(1) | $ | 1,119,627 | $ | 1,081,392 | $ | 2,922,027 | $ | 7,211,823 | $ | 7,630,307 | ||||||||||
| Total debt(1) | $ | 37,502 | $ | 305,308 | $ | 3,562,378 | $ | 3,148,034 | $ | 3,140,419 | ||||||||||
| Total stockholders’ equity (deficit) | $ | 839,940 | $ | 512,917 | $ | (1,187,733 | ) | $ | 3,209,820 | $ | 3,175,627 | |||||||||
| Total liabilities and stockholders’ equity (deficit) | $ | 1,119,627 | $ | 1,081,392 | $ | 2,922,027 | $ | 7,211,823 | $ | 7,630,307 | ||||||||||
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 “Selected Financial Data” in Item 6 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 explorationacquisition, development and production activities in the U.S. Mid-Continent andMid-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 Colorado. Ourour 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:
(1)For the year ended December 31, 2021, North Park Basin properties were acquired duringhad 67 MBoe in oil production.
(2)For the fourth quarteryear ended December 31, 2020, North Park Basin had 940 MBoe in oil production.
42
Mid-Continent total production for the year ended December 31, 2021 and 2020 was comprised of Presentationthe following:
| Year Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Oil | 13.2 | % | 14.7 | % | |||||||
| NGL | 33.7 | % | 34.7 | % | |||||||
| Natural gas | 53.1 | % | 50.6 | % | |||||||
| Total | 100.0 | % | 100.0 | % | |||||||
Highlighted Events
•On February 5, 2021, we sold all of our oil and natural gas properties. Asproperties 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 certain operating resultsof customary effective date adjustments and key operating performance measures, including those related to production, average oil and natural gas selling prices, revenues and lease operating expenses, were not significantly impacted and certaina $0.8 million post-close adjustment made during the second half of the combined operating resultsyear. 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 Predecessor 2016 PeriodTrust).
•On July 9, 2021, Carl F. Giesler, Jr. submitted his resignation from his positions as CEO, President and as a member of the Successor 2016 PeriodBoard 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, 2016, are still comparable2021.
•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 certain operating resultsthe Company on any matter relating to the Company’s operations, policies or practices.
43
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 years presented. Accordingly, we believe that discussingfactors 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 combined resultsimpact of operations and cash flows ofCOVID-19 lessens, demand for commodities is continuing to rise to pre-pandemic levels within the Predecessor Company and the Successor Company for the two periods in 2016 is useful when analyzing certain performance measures. For items that are not comparable, we have included additional analysisUnited States. The resurging demand led to supplement the discussion.
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, and changes in the fair value of our commodity derivative contracts.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, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| NYMEX Oil (per Bbl) | $ | 68.18 | $ | 39.19 | |||||||||||||
| NYMEX Natural gas (per MMBtu) | $ | 3.90 | $ | 2.13 | |||||||||||||
| Year Ended December 31, | |||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | |||||||||||||||
| Oil (per Bbl) | $ | 50.85 | $ | 43.47 | $ | 48.75 | $ | 92.91 | $ | 98.05 | |||||||||
| Natural gas (per Mcf) | $ | 3.02 | $ | 2.55 | $ | 2.62 | $ | 4.26 | $ | 3.73 | |||||||||
In order to reduce our exposure to price fluctuations, from time to time we have historically enteredenter into commodity derivative contracts for a portion of our anticipated future oil, and natural gas, and NGL production as discussed in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” ReducingDuring periods where the Company’s exposure to price volatility helps mitigate the risk that we will not have adequate funds availablestrike prices for our capital expenditure programs.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
2021 Acquisitions and Divestitures
On April 22, 2021, we announced the acquisition of NW STACK Properties. 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 10, 2017,5, 2021, we acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, net of post-closing adjustments. Also included in the acquisition were working interests in four wells previously drilled on the acreage.
On September 10, 2020, the Company acquired all of Piñthe 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
44
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 Gathering Company, LLC. In October 2015, we acquired the assetspreviously announced sale of and terminated a gas gathering agreement with PGCits corporate headquarters building located in Oklahoma City, OK, for $48.0 million cash and $78.0 million principal amount of Senior Secured Notes. PGC’s assets consistednet proceeds of approximately 370 miles ofgathering lines that supported our production in the Piñon field in West Texas. The transaction resulted in the termination of a gas gathering agreement with PGC under which we were required to compensate PGC for any throughput shortfalls below a required minimum volume. The fair value of the consideration we paid, including the discount attributable to the Senior Secured Notes issued, was approximately $98.3 million and was allocated on a relative fair value basis between the assets acquired (approximately $47.3 million) and a loss on the termination of the gathering contract (approximately $51.0 million). These assets were subsequently transferred to Occidental in the divestiture of the WTO properties discussed above.$35.4 million.
Oil, Natural Gas and NGL Production and Pricing
Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| 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 | |||||||||||||
| Successor | Predecessor | Combined | Predecessor | ||||||||||||||||
Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| Production data (in thousands) | |||||||||||||||||||
| Oil (MBbls) | 4,157 | 1,214 | 4,315 | 5,529 | 9,600 | ||||||||||||||
| NGL (MBbls) | 3,376 | 999 | 3,358 | 4,357 | 5,044 | ||||||||||||||
| Natural gas (MMcf) | 44,237 | 12,771 | 44,124 | 56,895 | 92,105 | ||||||||||||||
| Total volumes (MBoe) | 14,906 | 4,342 | 15,027 | 19,369 | 29,995 | ||||||||||||||
| Average daily total volumes (MBoe/d) | 40.8 | 47.7 | 54.6 | 52.9 | 82.2 | ||||||||||||||
| Average prices—as reported(1) | |||||||||||||||||||
| Oil (per Bbl) | $ | 48.72 | $ | 47.03 | $ | 36.85 | $ | 39.09 | $ | 45.83 | |||||||||
| NGL (per Bbl) | $ | 18.16 | $ | 14.77 | $ | 12.67 | $ | 13.15 | $ | 14.36 | |||||||||
| Natural gas (per Mcf) | $ | 2.09 | $ | 2.07 | $ | 1.78 | $ | 1.84 | $ | 2.12 | |||||||||
| Total (per Boe) | $ | 23.90 | $ | 22.64 | $ | 18.63 | $ | 19.53 | $ | 23.59 | |||||||||
| Average prices—including impact of derivative contract settlements(2) | |||||||||||||||||||
| Oil (per Bbl) | $ | 49.75 | $ | 54.59 | $ | 51.05 | $ | 51.83 | $ | 76.80 | |||||||||
| NGL (per Bbl) | $ | 18.16 | $ | 14.77 | $ | 12.67 | $ | 13.15 | $ | 14.36 | |||||||||
| Natural gas (per Mcf) | $ | 2.15 | $ | 1.96 | $ | 1.77 | $ | 1.81 | $ | 2.45 | |||||||||
| Total (per Boe) | $ | 24.38 | $ | 24.41 | $ | 22.70 | $ | 23.08 | $ | 34.51 | |||||||||
The table below presents production by area of operation for the yearyears ended December 31, 2017, the Successor2021 and Predecessor 2016 Periods and the year ended December 31, 2015, and illustrates the impact2020.
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||||||||||||||
| Production (MBoe) | % of Total Production | Production (MBoe) | % of Total Production | ||||||||||||||||||||||||||||||||
| Mid-Continent | 6,726 | 99.0 | % | 7,763 | 89.2 | % | |||||||||||||||||||||||||||||
| North Park Basin | 67 | 1.0 | % | 940 | 10.8 | % | |||||||||||||||||||||||||||||
| Total | 6,793 | 100.0 | % | 8,703 | 100.0 | % | |||||||||||||||||||||||||||||
45
Table of (i) the continued decrease in capital expenditures and number of new wells drilled in the Mid-Continent, (ii) drilling no new wells in the Permian and other regions during 2016 and 2017, and (ii) the acquisition of the North Park Basin properties in December 2015.Contents
| Successor | Predecessor | ||||||||||||||||||||||
| Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | ||||||||||||||||||||
| 2017 | 2016 | 2016 | 2015 | ||||||||||||||||||||
| Production (MBoe) | % of Total Production | Production (MBoe) | % of Total Production | Production (MBoe) | % of Total Production | Production (MBoe) | % of Total Production | ||||||||||||||||
| Mid-Continent | 13,720 | 92.1 | % | 4,018 | 92.5 | % | 14,119 | 94.0 | % | 26,558 | 88.5 | % | |||||||||||
| North Park Basin | 673 | 4.5 | % | 180 | 4.1 | % | 320 | 2.1 | % | — | — | % | |||||||||||
| Permian Basin | 513 | 3.4 | % | 144 | 3.4 | % | 489 | 3.3 | % | 1,567 | 5.2 | % | |||||||||||
| Other | — | — | % | — | — | % | 99 | 0.6 | % | 1,870 | 6.3 | % | |||||||||||
| Total | 14,906 | 100.0 | % | 4,342 | 100.0 | % | 15,027 | 100.0 | % | 29,995 | 100.0 | % | |||||||||||
Revenues
Consolidated revenues for the year ended December 31, 2017, the Successor 2016 Period, the Predecessor 2016 Period, and the years ended December 31, 20162021 and 20152020 are presented in the table below (in thousands).
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Revenues | |||||||||||||||||
| Oil | $ | 62,297 | $ | 73,621 | |||||||||||||
| NGL | 50,836 | 17,962 | |||||||||||||||
| Natural gas | 55,749 | 22,867 | |||||||||||||||
| Other | — | 526 | |||||||||||||||
| Total revenues | $ | 168,882 | $ | 114,976 | |||||||||||||
| Successor | Predecessor | Combined | Predecessor | ||||||||||||||||
| Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| Revenues | |||||||||||||||||||
| Oil | $ | 202,539 | $ | 57,093 | $ | 159,023 | $ | 216,116 | $ | 439,927 | |||||||||
| NGL | 61,322 | 14,756 | 42,541 | 57,297 | 72,440 | ||||||||||||||
| Natural gas | 92,349 | 26,458 | 78,407 | 104,865 | 195,067 | ||||||||||||||
| Other | 1,089 | 149 | 13,838 | 13,987 | 61,275 | ||||||||||||||
| Total revenues(1) | $ | 357,299 | $ | 98,456 | $ | 293,809 | $ | 392,265 | $ | 768,709 | |||||||||
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, 20172021 and 20162020 are shown in the table below (in thousands):
| 2015 oil, natural gas and NGL revenues | $ | 707,434 | |
| Change due to production volumes in 2016 | (270,688 | ) | |
| Change due to average prices in 2016 | (58,468 | ) | |
2016 oil, natural gas and NGL revenues (supplemental pro forma combined) | 378,278 | ||
| Change due to production volumes in 2017 | (90,073 | ) | |
| Change due to average prices in 2017 | 68,005 | ||
| 2017 oil, natural gas and NGL revenues | $ | 356,210 | |
2020 oil, natural gas and NGL revenues | $ | 114,450 | |||
| Change due to production volumes in 2021 | (47,453) | ||||
| Change due to average prices in 2021 | 101,885 | ||||
| 2021 oil, natural gas and NGL revenues | $ | 168,882 | |||
Oil, natural gas and NGL revenues decreasedincreased by a combined $22.1$54.4 million, or 5.8% for the year ended December 31, 2017, compared to 2016. The decrease is due largely to a 4.5 MMBoe decrease in total production, primarily due to natural declines in existing producing wells and fewer wells brought on production. This decrease was partially offset by an increase in average prices received for our oil, NGL and natural gas production. Additionally, the average prices received in the 2017 period include the full effect of the Successor Company’s election to include transportation deductions in revenues as discussed below, whereas the combined 2016 period only includes the impact of this election for the Successor 2016 Period.
Operating Expenses
Operating expenses for the Successor 2016 Period.
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Lease operating expenses | $ | 35,999 | $ | 43,431 | |||||||||||||
| Production, ad valorem, and other taxes | 9,918 | 9,634 | |||||||||||||||
| Depreciation and depletion—oil and natural gas | 9,372 | 50,349 | |||||||||||||||
| Depreciation and amortization—other | 6,073 | 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, 2017, the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2016 and 2015 are presented below.2021.
46
| Successor | Predecessor | Combined | Predecessor | ||||||||||||||||
| Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| (In thousands) | |||||||||||||||||||
| Expenses | |||||||||||||||||||
| Production | $ | 102,728 | $ | 24,997 | $ | 129,608 | $ | 154,605 | $ | 308,701 | |||||||||
| Production taxes | 13,644 | 2,643 | 6,107 | 8,750 | 15,440 | ||||||||||||||
| Depreciation and depletion—oil and natural gas | 118,035 | 36,061 | 90,978 | 127,039 | 324,390 | ||||||||||||||
| Depreciation and amortization—other | 13,852 | 3,922 | 21,323 | 25,245 | 47,382 | ||||||||||||||
| Impairment | 4,019 | 319,087 | 718,194 | 1,037,281 | 4,534,689 | ||||||||||||||
| General and administrative | 76,024 | 9,837 | 116,091 | 125,928 | 137,715 | ||||||||||||||
| Terminated merger costs | 8,162 | — | — | — | — | ||||||||||||||
| Employee termination benefits | 4,815 | 12,334 | 18,356 | 30,690 | 12,451 | ||||||||||||||
| (Gain) loss on derivative contracts | (24,090 | ) | 25,652 | 4,823 | 30,475 | (73,061 | ) | ||||||||||||
| Loss on settlement of contract | — | — | 90,184 | 90,184 | 50,976 | ||||||||||||||
| Other operating expense | 479 | 268 | 4,348 | 4,616 | 52,704 | ||||||||||||||
| Total expenses(1) | $ | 317,668 | $ | 434,801 | $ | 1,200,012 | $ | 1,634,813 | $ | 5,411,387 | |||||||||
Production, expense includes but is not limited to, lease operating expensead valorem, and treating costs. Production expenses for 2017 decreased $51.9 million, or 33.6% from combined 2016 production expenses. Production costs per Boe decreased to $6.89 per Boe for the 2017 period from $7.98 per Boe in 2016,other taxes has increased primarily due to (i) the Successor Company’s presentation of transportation costs totaling $29.1 million ashigher commodity prices in 2021 partially offset by a reduction from revenues for the year ended December 31, 2017, compareddecline in ad valorem taxes due to the presentationsale of only $7.4 million of transportation costs asNPB in Colorado and a reduction from revenues in the Successor 2016 Period with the remaining 2016 transportation costs of $26.2 million being presented as production expenses by the Predecessor Company, and (ii) controlled reductions in expenditures for electricity, chemicals and various other costs. Production expenses for 2016 decreased $154.1 million, or 49.9% from 2015. Production costs per Boe decreased to $7.98 per Boe for the 2016 period from $10.29 per Boe in 2015, primarily due to (i) a decrease in well activity due to fewer new wells being brought on production, (ii) termination of the CO2 delivery agreement with Occidental in the first quarter of 2016, which resulted in CO2 delivery shortfall penalties of $2.0 million being incurred in the Predecessor 2016 Period compared to penalties of $34.9 million incurred during 2015, and (iii) the presentation of transportation costs as a reduction from revenues in the Successor 2016 Period versus the Predecessor Company’s presentation of these costs as production expenses.
Depreciation and depletion for oil and natural gas properties decreased by $9.0$41.0 million for the year ended December 31, 20172021 compared to the combined 2016 periods, primarily2020 due to thea decrease in production. This decrease was partially offset by an increase in the average depreciation and depletion rate to $7.92$1.38 per Boe in 20172021 compared to an average rate of $6.56 per Boe for the combined 2016 periods. This increase$5.79 in the average rate primarily resulted from (i) incurring higher actual drilling and
Impairment
Impairment expense for the year ended December 31, 2017, the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 20162021 and 20152020 consisted of the following (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Impairment | |||||||||||||||||
| Full cost pool ceiling limitation | $ | — | $ | 218,399 | |||||||||||||
| Other | — | 38,000 | |||||||||||||||
| Total impairment | $ | — | $ | 256,399 | |||||||||||||
| Successor | Successor | Predecessor | Combined | Predecessor | |||||||||||||||
| Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| Impairment | |||||||||||||||||||
| Full cost pool ceiling limitation | $ | — | $ | 319,087 | $ | 657,392 | $ | 976,479 | $ | 4,473,787 | |||||||||
| Drilling assets | 4,019 | — | 3,511 | 3,511 | 37,646 | ||||||||||||||
| Electrical infrastructure assets | — | — | 55,600 | 55,600 | — | ||||||||||||||
| Midstream assets | — | — | 1,691 | 1,691 | 7,148 | ||||||||||||||
| Other | — | — | — | — | 16,108 | ||||||||||||||
| Total impairment | $ | 4,019 | $ | 319,087 | $ | 718,194 | $ | 1,037,281 | $ | 4,534,689 | |||||||||
Full cost pool impairment. UponWe did not record a full cost ceiling limitation impairment for the applicationyear ended December 31, 2021. Impairment for the year ended December 31, 2020 largely resulted from an impairment charge of fresh start accounting,$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 Successor CompanyCompany's building headquarters to its estimated fair value less estimated costs to sell the building headquarters.
Calculation of the full cost pool was determinedceiling test is based upon forward strip oil and natural gason, 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 the Emergence Date. Because these prices were higher than the 12-month weighted average prices usedproved reserves included in the full cost ceiling limitation calculationtest at December 31, 2016,2021 were $66.56 per barrel of oil and $3.60 per Mcf of natural gas, before price differential adjustments.
Based on the Successor Company incurred aSEC 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 $319.1 million.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 impairment recorded for the Predecessor Company in 2016 was dueimpairments have no impact to full cost ceiling limitations recognized in eachour cash flow or liquidity.
47
Table of the first three quarters of 2016. The impairments recorded in 2015 and the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes. The decrease in projected production volumes resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that have been developed with three or more horizontal wells per section as inter-well pressure communication has had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in the Company’s Mississippian wells producing with artificial lift have resulted in increased production decline rates that are now becoming more predictable on a large group of base wells as this population of wells has been producing for more than two years.Contents
Other Operating Expenses
Other operating expenses for sale to net realizable value. Impairments were recorded on certain drilling assets in the years ended December 31, 2016,2021 and 2015 upon determining their future use was limited after discontinuing drilling operations in the Permian region in 2015 and discontinuing all remaining drilling operations in 2016.
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| General and administrative | $ | 9,675 | $ | 15,327 | |||||||||||||
| Restructuring expenses | 792 | 2,733 | |||||||||||||||
| Employee termination benefits | 49 | 8,433 | |||||||||||||||
| (Gain) loss on derivative contracts | 2,251 | (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 $49.9$5.7 million, or 39.6%36.9%, for the year ended December 31, 20172021 compared to 2016 due2020. These decreases resulted primarily to (i)from a decrease of $25.0 millionreduction in professional servicescompensation related costs due to incurring significant consultant and legal fees in the 2016 period in contemplation of the Company’s restructuring, and (ii) a $23.6 million decrease in net salary costs largely resulting fromafter completing reductions in force during the first and fourth quarters of 2016. The remaining change is due to the net effect of2020, significant reductions in directorinformation technology and officer insurancesoftware costs bad debt expense, and costs largelyoverhead expenses related to the reductionCompany's previously held corporate headquarters building. Part of the decrease is also due to reductions in headcount duringprofessional costs such as legal expenses, audit fees and consulting services.
Restructuring expenses represent fees and costs associated with the 2016 offset partially by increasesbankruptcy and exit from NPB in other miscellaneous general and administrative items.
Employee termination benefits for the yearyears ended December 31, 2017, primarily relate to2021 and 2020, includes cash and share-based severance costs incurred for reductions in conjunction withforce. The decrease from 2020 to 2021 is primarily the departureresult of separations of employment for Company employees during 2020, that did not occur in 2021. As a former executive. Employee termination benefits forresult, the year ended December 31, 2016, representCompany paid cash severance costs and incurred primarily as a result of (i) reductions in force in the first and fourth quarters of 2016, (ii) severanceshare-based compensation costs associated with the departureseparations in 2020, with no recurrence of executive officers and other senior officers and (iii) discontinuing all remaining drilling and oilfield services operations and the majority of all midstream and marketing services operationssuch costs in 2021. See "Note 13 - Employee Termination Benefits" in the first quarteraccompanying consolidated financial statements in Item 8 of 2016.this report for additional discussion of these expenses.
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 each quarterquarterly 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.” Gains or losses on early settlements and losses related to amendments of contracts are not considered in the calculation of 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.
48
Other Income (Expense)
Other income (expense) for the years ended December 31, 2021 and 2020 is reflected in the Predecessor 2016 Period consists of a $78.9 million loss resulting from the termination of a gas treating and COtable below (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Other (expense) income | |||||||||||||||||
| Interest expense, net | $ | (404) | $ | (1,998) | |||||||||||||
| Other (expense) income , net | 3,055 | (2,494) | |||||||||||||||
| Total other (expense) income | $ | 2,651 | $ | (4,492) | |||||||||||||
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Interest expense | |||||||||||||||||
| Interest expense on debt | $ | 377 | $ | 2,386 | |||||||||||||
| Interest expense on right of use assets | 26 | 114 | |||||||||||||||
| Write off of debt issuance costs | 174 | 266 | |||||||||||||||
| Amortization of debt issuance costs, premium and discounts | 57 | — | |||||||||||||||
| Capitalized interest | (252) | (750) | |||||||||||||||
| Interest expense - other | 25 | 1 | |||||||||||||||
| Total | 407 | 2,017 | |||||||||||||||
| Less: interest income | (3) | (19) | |||||||||||||||
| Total interest expense, net | $ | 404 | $ | 1,998 | |||||||||||||
See “—Acquisitions and Divestitures” above and see “Note 6—Acquisitions and Divestitures”11—Long-Term Debt” to the Company’s accompanyingconsolidated financial statements in Item 8 of this report for additional discussion of the acquisition of PGC and the PGC gathering agreement.
The Other (expense) income, net line item for the year ended December 31, 2017,2021 is primarily comprised of the Successor 2016 Period,removal of $2.4 million of an allowance for doubtful accounts as a result of the Predecessor 2016 Period and the years ended December 31, 2016, and 2015, is reflected in the table below (in thousands).
| Successor | Predecessor | Combined | Predecessor | ||||||||||||||||
| Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| Other (expense) income | |||||||||||||||||||
| Interest expense | $ | (3,868 | ) | $ | (372 | ) | $ | (126,099 | ) | $ | (126,471 | ) | $ | (321,421 | ) | ||||
| Gain on extinguishment of debt | — | — | 41,179 | 41,179 | 641,131 | ||||||||||||||
| Reorganization items | — | — | 2,430,599 | 2,430,599 | — | ||||||||||||||
| Other income, net | 2,550 | 2,744 | 1,332 | 4,076 | 2,040 | ||||||||||||||
| Total other (expense) income | $ | (1,318 | ) | $ | 2,372 | $ | 2,347,011 | $ | 2,349,383 | $ | 321,750 | ||||||||
| Successor | Successor | Predecessor | Combined | Predecessor | |||||||||||||||
Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| Interest expense | |||||||||||||||||||
| Interest expense on debt | $ | 5,216 | $ | 1,590 | $ | 123,350 | $ | 124,940 | $ | 304,020 | |||||||||
| Amortization of debt issuance costs, premium and discounts | (330 | ) | (81 | ) | 7,730 | 7,649 | 15,014 | ||||||||||||
| Write off of debt issuance costs | — | — | — | — | 7,108 | ||||||||||||||
| (Gain) loss on long-term debt derivatives | — | — | (1,324 | ) | (1,324 | ) | 10,377 | ||||||||||||
| Capitalized interest | — | — | (2,240 | ) | (2,240 | ) | (14,018 | ) | |||||||||||
| Total | 4,886 | 1,509 | 127,516 | 129,025 | 322,501 | ||||||||||||||
| Less: interest income | (1,018 | ) | (1,137 | ) | (1,417 | ) | (2,554 | ) | (1,080 | ) | |||||||||
| Total interest expense | $ | 3,868 | $ | 372 | $ | 126,099 | $ | 126,471 | $ | 321,421 | |||||||||
49
Liquidity and Capital Resources
At December 31, 2017,2021, our cash and cash equivalents, excludingincluding restricted cash, were $99.1was $139.5 million. Additionally,The 2020 Credit Facility was terminated, as discussed below. See "Note—11 Long-Term Debt" to the accompanyingconsolidated financial statements in Item 8 of this report for further discussion.For the next twelve months, we had approximately $37.5 million in total debt outstandingexpect to have ample liquidity with cash on hand and $6.7 million in outstanding letters of credit.cash from operations. As of February 15, 2018,March 9, 2022, the Company had approximately $77.8 million in cash and cash equivalents, excluding restricted cash, an undrawnno outstanding term or revolving debt obligations.
Our commodity derivative contracts are subject to credit facility, and $6.7 million in outstanding lettersrisk of credit, which reduceour counterparties being financially able to settle the amount available undertransaction. We monitor the credit facility.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 2017 include2021 included cash flow from operations and cash on hand and amounts available under our credit facility, as discussed in “—Credit Facility” below.hand.
We have established a rangeintend to spend between $41 million and $50 million in our 2022 capital budget plan, excluding any expenditures for our 2018acquisitions. We intend to fund capital expenditures budget between $180.0 million and $190.0 million, withother commitments for the substantial majority of the budgeted expenditures being designated for exploration and development activities. Management intends to fund 2018 capital expendituresnext 12 months using cash flowflows from our operations borrowings under the credit facility and cash on hand. Additionally, through changes in the organization structure and other effortsWe will endeavor to efficiently executekeep our strategic objectives, we expectcapital spending within or very close to reduce certain general and administrative expenses significantly beginning in 2018; however, we also expectour projected cash flows from operations subject to incur significant severance costs as a result of the organizational changes mentioned in “—Overview.”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, for oil,during the period from January 20132017 through December 2017,2021, the highest month end NYMEX settled price was $107.65for oil fluctuated between a high of $85.64 per Bbl and a low of $(36.98) per Bbl, and the lowest was $33.62 per Bbl. For natural gas, from January 2013 through December 2017, the highest month-end NYMEX settled price was $5.56for gas fluctuated between a high of $23.86 per MMBtu and the lowest was $1.71a 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 further 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 year ended December 31, 2017, the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 20162021, and 2015,2020 are presented in the following table and discussed below (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Cash flows provided by (used in) operating activities | $ | 110,260 | $ | 36,162 | |||||||||||||
| Cash flows provided by (used in) investing activities | 22,973 | 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 | |||||||||||||
50
| Successor | Predecessor | Combined | Predecessor | ||||||||||||||||
| Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| Cash flows provided by (used in) operating activities | $ | 181,179 | $ | 65,595 | $ | (112,077 | ) | $ | (46,482 | ) | $ | 373,537 | |||||||
| Cash flows used in investing activities | (245,724 | ) | (39,835 | ) | (167,690 | ) | (207,525 | ) | (1,039,640 | ) | |||||||||
| Cash flows (used in) provided by financing activities | (8,218 | ) | (415,061 | ) | 407,551 | (7,510 | ) | 920,438 | |||||||||||
| Net (decrease) increase in cash and cash equivalents | $ | (72,763 | ) | $ | (389,301 | ) | $ | 127,784 | $ | (261,517 | ) | $ | 254,335 | ||||||
Cash Flows from Operating Activities
The $227.7$74.1 million increase in operating cash flows for the year ended December 31, 20172021 compared to 2016,2020, is primarily due to (i) anet 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 cash paid for interest expense, (ii) a decreasedecreases in professionallease operating expenses and other fees paid in connection with the Company’s restructuring in 2016, (iii) a reduction in payroll and other employee related general and administrative costs, (iv) a reductionexpenses. The increase in production expenses, and (v) the 2016 period including cash payments for the early conversion of notes and the settlement of contracts. These decreases in expenses werenet income was partially offset by reductionsthe addback of the gain on sale of assets primarily related to NPB and a reduction of accrued liabilities over and above an increase in cash received for the settlement of derivativesour receivable and lower revenues in 2017 compared to 2016. 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, 2017,2021, cash flows used inprovided by investing activities consisted primarily reflects $38.2 million of net cash proceeds primarily from the sale of NPB assets partially offset by capital expenditures for our exploration and development operationsof $11.6 million and the acquisition of 13,000 net acres in Woodward County, Oklahomaoverriding royalty interests for approximately $47.8 million in cash and capital expenditures for exploration and development, which were partially offset by proceeds from the sale of various non-core oil and natural gas properties and certain drilling equipment previously classified as held for sale.$3.6 million.
During the year ended December 31, 2016,2020, cash flows used inprovided by investing activities consisted 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 3— Acquisitions, Divestitures and Disposal of Assets and Oil and Gas Properties" to the accompanying consolidated financial statements included in Item 8 of this report for our exploration and development operations. During the year ended December 31, 2015, cash flows used in investing activities largely consisted of capital expenditures, excluding acquisitions, as well as cash paid for the North Park acquisition and the PGC assets acquired.additional information.
Capital Expenditures. The Company’s
Our capital expenditures on an accrual basis,for the years ended December 31, 2021 and 2020, are summarized below (in thousands):
Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Capital Expenditures | |||||||||||||||||
| Drilling, completion, and capital workovers | $ | 10,045 | $ | 3,563 | |||||||||||||
| Leasehold and geophysical | 905 | 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 acquisitions | 14,495 | 8,269 | |||||||||||||||
| Change in capital accruals | 633 | 4,194 | |||||||||||||||
| Total cash paid for capital expenditures | $ | 15,128 | $ | 12,463 | |||||||||||||
____________________
(1)Excludes $3.9 million for the year ended December 31, 2017, the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2016 and 2015 are summarized below (in thousands):2020, related to non-monetary transactions.
| Successor | Predecessor | Combined | Predecessor | ||||||||||||||||
Year Ended December 31, | Period from October 2, 2016 through December 31, | Period from January 1, 2016 through October 1, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||
| 2017 | 2016 | 2016 | 2016 | 2015 | |||||||||||||||
| Capital Expenditures (on an accrual basis) | |||||||||||||||||||
| Exploration and development | $ | 246,033 | $ | 38,062 | $ | 155,627 | $ | 193,689 | $ | 656,022 | |||||||||
| Other - operating | 854 | 2,901 | 3,108 | 6,009 | 26,188 | ||||||||||||||
| Other - corporate | 1,358 | 83 | 2,672 | 2,755 | 19,405 | ||||||||||||||
| Capital expenditures, excluding acquisitions | 248,245 | 41,046 | 161,407 | 202,453 | 701,615 | ||||||||||||||
| Acquisitions | 48,312 | — | 1,328 | 1,328 | 241,165 | ||||||||||||||
| Total | $ | 296,557 | $ | 41,046 | $ | 162,735 | $ | 203,781 | $ | 942,780 | |||||||||
Capital expenditures, excluding acquisitions, for explorationdevelopment and developmentproduction activities increased for the year ended December 31, 20172021 compared to 2016, primarily due to drilling longer laterals2020, which is in line with the North Park Basin, which are more capital intensive.planned increase in costs as result of our well reactivation program.
Cash Flows from Financing Activities
Our financing activities used $8.2$22.0 million in of cash for the year ended December 31, 2017, which consisted2021, 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 taxes upon the vestingtax obligations on vested stock awards of employee share-based compensation awards and deferred financing costs incurred on the credit facility.$0.9 million.
51
Indebtedness
Credit Facility
| Credit facility | $ | — | |
| Building Note | 37,502 | ||
| Total debt | $ | 37,502 | |
On February 10, 2017,November 30, 2020, the New First Lien Exit Facility was refinanced into a new $600.0 million credit facility with a $425.0 million borrowing base. The new credit facility agreement had the following impacts:
On September 2, 2021, we repaid our $20.0 million term loan in full and gas real property in downtown Oklahoma City, Oklahoma. The Building Note was recorded at fair value ($36.6 million) upon implementation of fresh start accounting. Interest is payable onterminated all commitments and obligations under the Building Note at 6% per annum for the first year following the Emergence Date, 8% per annum for the second year following the Emergence Date,2020 Credit Facility, between us, as Borrower, IEP Energy Holding LLC, as Lender, and 10% thereafter through maturity. Interest on the Building Note was initially payable in kind. Approximately $1.3 million in in-kind interest costs were addedIcahn Agency Services LLC, as Administrative Agent. Our payment to the Building Note principal fromLender under the Emergence Date through May 11, 2017, which was 90 days after the refinancingCredit Agreement satisfied all of our term debt and revolving debt obligations. We did not incur any early termination penalties as a result of the First Lien Exit Facility. Interest became payable thereafter in cash. The Building Note matures on October 2, 2021, and became prepayable in wholerepayment of indebtedness or in part without premium or penalty upon the refinancingtermination of the First Lien Exit Facility. On February 14, 2018, the Company gave notice to the holder of the Building Note of its intent to prepay the Building Note in full during the first quarter of 2018.
Credit Agreement. See “Note 12 - 11—Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt.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, 2017,2021, our contractual obligations included long-term debt obligations, third-party drilling rig agreements, asset retirement obligations, operatingshort 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 standby letters of credit and 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 letters of credit and surety bonds.bonds or other instruments.
As of December 31, 2017,2021, we had future contractual payment commitments under various agreements, which are summarized below. The third-party drilling rig and operating leases are not recorded in the accompanying consolidated balance sheets.
| Payments Due by Period | |||||||||||||||||||
| Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |||||||||||||||
| (In thousands) | |||||||||||||||||||
| Long-term debt obligations(1) | $ | 49,814 | $ | 3,181 | $ | 7,529 | $ | 39,104 | $ | — | |||||||||
| Third-party drilling rig agreements(2) | 3,400 | 3,400 | — | — | — | ||||||||||||||
| Asset retirement obligations(3) | 77,544 | 41,017 | — | — | 36,527 | ||||||||||||||
| Operating leases and other(4) | 12,039 | 8,827 | 1,688 | 380 | 1,144 | ||||||||||||||
| Total | $ | 142,797 | $ | 56,425 | $ | 9,217 | $ | 39,484 | $ | 37,671 | |||||||||
| Payments Due by Period | |||||||||||||||||||||||||||||
| Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Asset retirement obligations (1) | $ | 59,368 | $ | 17,606 | $ | 116 | $ | 47 | $ | 41,599 | |||||||||||||||||||
| Operating lease | 167 | 167 | |||||||||||||||||||||||||||
| Finance lease | 779 | 351 | 428 | — | — | ||||||||||||||||||||||||
| Total | $ | 60,314 | $ | 18,124 | $ | 544 | $ | 47 | $ | 41,599 | |||||||||||||||||||
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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 an estimatedsignificant U.S. federal net operating loss of approximately $1.3 billionlosses remaining after the attribute reduction caused by the restructuring transactions. As such, the Successorsuccessor 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 September 30, 2017.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. The “Tax Cuts and Jobs Act” (the “TCJA”) enacted in December 2017 includes significant changes to the taxation of business entities, most of which are effective for taxable years beginning after December 31, 2017. These changes were taken into consideration when evaluating the reversal periods of existing deferred tax liabilities and deferred tax assets and the prospects of future earnings.
In determining whether to maintain the valuation allowance at December 31, 2017,2021, 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, 2017,2021, 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, 2017.2021.
See “Note 19 - 14—Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional discussion of income tax related matters.
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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 the Companymanagement 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. The Company bases its estimatesEstimates are based on historical experience and various other assumptions that the Company believes arebelieved to be reasonable; however, actual results may differ significantly. The Company’s critical accounting policies and additional information on significant estimates used by the Company are discussed below. See “Note 3—1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report for additional discussion of the Company’s significant accounting policies.
Proved Reserves. Approximately 95.4%Over 96.0% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2017.2021. 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, and thedata. 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, 2017, 20162021 and 2015,2020, the Company revised its proved reserves from prior years’ reports by approximately 10.9 MMBoe, (105.4)43.3 MMBoe and (234.6)(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, market prices during or at the end of the applicable period, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings
within the original field boundaries.boundaries among other factors. Estimates of proved reserves are key components of the Company’s most significant 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. As part of fresh start accounting, proved reserves were adjusted to their estimated fair value as of October 1, 2016, as described in “Note 2—Fresh Start Accounting.”
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 present value of future net revenues from proved oil, natural gas and 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 (the “ceiling limitation”).ceiling limitation. The Company calculates its full cost ceiling limitation using the 12-month average oil and natural gasSEC prices for the most recent 12 months as of the balance sheet date and adjusted for basis or location differential,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 Successor Company recorded full cost ceiling did not record any impairment of $319.1 million for the period from October 2, 2016 through December 31, 2016, and the Predecessor Company recorded full cost ceiling impairments of $657.4 million and $4.5 billion for the period from January 1, 2016 through October 1, 2016, and the year ended December 31, 2015, respectively. No full cost ceiling impairment was recorded for the year ended December 31, 2017.2021 and $218.4 million for the year ended December 31, 2020. See “Consolidated“—Consolidated Results of Operations” for additional discussion of full cost ceiling impairments.
See “—Consolidated Results of Operations” and “Note 10—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
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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, 2017,2021, 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 3—1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report.
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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. Our credit facility limits our ability to enter into derivative transactions to 90% of expected production volumes from estimated proved reserves.
We use, and may continue to use a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At December 31, 2017, our commodity2021, the Company's open derivative contracts consisted of fixed price swapsnatural 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. In light of the high correlation between NGL and oil prices, for 2018 we plan to manage a portion of our NGL price exposure using oil fixed price swaps at a three-to-one (3:1) NGL to crude oil ratio.
| Notional | Units | Weighted Average Fixed Price per Unit | ||||||||||||||||||
| NGL Price Swaps: January 2022 - February 2022 | 1,042,000 | Gallons | $ | 1.20 | ||||||||||||||||
| Natural Gas Price Swaps: January 2022 - February 2022 | 720,000 | MMBtu | $ | 4.07 | ||||||||||||||||
| Notional (MBbls) | Weighted Average Fixed Price | |||||
| January 2018 - December 2018 | 3,464 | $ | 55.08 | |||
| January 2019 - December 2019 | 1,460 | $ | 53.34 | |||
| Notional (MMcf) | Weighted Average Fixed Price | |||||
| January 2018 - December 2018 | 17,300 | $ | 3.16 | |||
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 as of period-end to the contract price.price at the period-end.
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Loss (gain) on commodity derivative contracts | $ | 2,251 | $ | (5,765) | |||||||||||||
| Cash paid (received) on settlements | $ | 2,230 | $ | (5,879) | |||||||||||||
See “Note 13—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. OurHistorically, derivative contracts arehave been with multiple counterparties to minimize exposure to any individual counterparty.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 each of 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. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against amounts owed, if any, to such counterparty. As of December 31, 2017, the counterparties to our open commodity derivative contracts consisted of seven financial institutions, all of which are also lenders under the credit facility. As a result,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.
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Interest Rate Risk. We arewere exposed to interest rate risk on our credit facility. Thisunder the 2020 Credit Facility. The variable interest rate on our credit facility fluctuates,2020 Credit Facility fluctuated, and exposesexposed us to short-term changes in market interest rates as our interest obligations on this instrument iswere periodically redetermined based on prevailing market interest rates, primarily LIBOR andLIBOR. The 2020 Credit Facility was terminated during the federal funds rate. We had no outstanding variable rate debt assecond half of December 31, 2017.2021. See "Note—11 Long-Term Debt" to the accompanyingconsolidated financial statements in Item 8 of this report for further discussion.
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Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page(s) | |||||
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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, 2017.2021. 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, 2017.2021.
/s/ | /s/ | |||||||
President, | ||||||||
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To the stockholders and the Board of Directors and Stockholders of SandRidge Energy, Inc.
We have audited the accompanying consolidated balance sheets of SandRidge Energy, Inc. and its subsidiaries (Successor Company)(the "Company") as of December 31, 20172021 and 2016,and2020, the related consolidated statements of operations, changes in stockholders’stockholders' equity, (deficit) and cash flows,for each of the yearthree years in the period ended December 31, 20172021, and the period from October 2, 2016 to December 31, 2016, including the related notes (collectively referred to as the “consolidated financial statements”"financial statements").We also have audited the Company's internal control over financial reporting as of December 31, 2017, 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 consolidatedfinancial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172021 and 2016, 2020, and the results of theirits operations and theirits cash flows for each of the yearthree years in the period ended December 31, 2017 and the period from October 2, 2016 to December 31, 20162021, in conformity with accounting principles generally accepted in the United States of America. Also
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.
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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.
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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, 2017,2021, based on criteria established in Internal Control -— Integrated Framework(2013) issued by the COSO.
Basis for OpinionsOpinion
The Company'sCompany’s management is responsible for these consolidated financial statements, 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'sManagement’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinionsan opinion on the Company’s consolidatedfinancial statements and on the Company's internal control over financial reporting based on our audits.audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")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 auditsaudit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditsaudit to obtain reasonable assurance about whether the consolidatedfinancial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
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 (i)(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; (ii)(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 (iii)(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, | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | 137,260 | $ | 22,130 | |||||||
| Restricted cash - other | 2,264 | 6,136 | |||||||||
| Accounts receivable, net | 21,505 | 19,576 | |||||||||
| Prepaid expenses | 626 | 2,890 | |||||||||
| Other current assets | 80 | 80 | |||||||||
| Total current assets | 161,735 | 50,812 | |||||||||
| Oil and natural gas properties, using full cost method of accounting | |||||||||||
| Proved | 1,454,016 | 1,463,950 | |||||||||
| Unproved | 12,255 | 17,964 | |||||||||
| Less: accumulated depreciation, depletion and impairment | (1,373,217) | (1,375,692) | |||||||||
| 93,054 | 106,222 | ||||||||||
| Other property, plant and equipment, net | 97,791 | 103,118 | |||||||||
| Other assets | 332 | 680 | |||||||||
| Total assets | $ | 352,912 | $ | 260,832 | |||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable and accrued expenses | $ | 45,779 | $ | 51,426 | |||||||
| Asset retirement obligations | 17,606 | 16,467 | |||||||||
| Derivative contracts | 21 | — | |||||||||
| Other current liabilities | 627 | 984 | |||||||||
| Total current liabilities | 64,033 | 68,877 | |||||||||
| Long-term debt | — | 20,000 | |||||||||
| Asset retirement obligations | 41,762 | 40,701 | |||||||||
| Other long-term obligations | 1,795 | 3,188 | |||||||||
| Total liabilities | 107,590 | 132,766 | |||||||||
| Commitments and contingencies (Note 13) | 0 | 0 | |||||||||
| 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 | |||||||||
| Warrants | 88,520 | 88,520 | |||||||||
| Additional paid-in capital | 1,062,737 | 1,062,220 | |||||||||
| Accumulated deficit | (905,972) | (1,022,710) | |||||||||
| Total stockholders’ equity | 245,322 | 128,066 | |||||||||
| Total liabilities and stockholders’ equity | $ | 352,912 | $ | 260,832 | |||||||
| December 31, | December 31, | ||||||
| 2017 | 2016 | ||||||
| ASSETS | |||||||
| Current assets | |||||||
| Cash and cash equivalents | $ | 99,143 | $ | 121,231 | |||
| Restricted cash - collateral | — | 50,000 | |||||
| Restricted cash - other | 2,165 | 2,840 | |||||
| Accounts receivable, net | 71,277 | 74,097 | |||||
| Derivative contracts | 1,310 | — | |||||
| Prepaid expenses | 5,248 | 5,375 | |||||
| Other current assets | 15,954 | 3,633 | |||||
| Total current assets | 195,097 | 257,176 | |||||
| Oil and natural gas properties, using full cost method of accounting | |||||||
| Proved (includes development and project costs excluded from amortization of $16.7 million at December 31, 2016) | 1,056,806 | 840,201 | |||||
| Unproved | 100,884 | 74,937 | |||||
| Less: accumulated depreciation, depletion and impairment | (460,431 | ) | (353,030 | ) | |||
| 697,259 | 562,108 | ||||||
| Other property, plant and equipment, net | 225,981 | 255,824 | |||||
| Other assets | 1,290 | 6,284 | |||||
| Total assets | $ | 1,119,627 | $ | 1,081,392 | |||
The accompanying notes are an integral part of these consolidated financial statements.
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SandRidge Energy, Inc. and Subsidiaries
Consolidated Balance Sheets—ContinuedStatements of Operations
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands, except per share amounts) | |||||||||||||||||
| Revenues | |||||||||||||||||
| Oil, natural gas and NGL | $ | 168,882 | $ | 114,450 | $ | 266,104 | |||||||||||
| Other | — | 526 | 741 | ||||||||||||||
| Total revenues | 168,882 | 114,976 | 266,845 | ||||||||||||||
| Expenses | |||||||||||||||||
| Lease operating expenses | 35,999 | 43,431 | 90,938 | ||||||||||||||
| Production, ad valorem, and other taxes | 9,918 | 9,634 | 19,394 | ||||||||||||||
| Depreciation and depletion—oil and natural gas | 9,372 | 50,349 | 146,874 | ||||||||||||||
| Depreciation and amortization—other | 6,073 | 7,736 | 11,684 | ||||||||||||||
| Impairment | — | 256,399 | 409,574 | ||||||||||||||
| General and administrative | 9,675 | 15,327 | 32,058 | ||||||||||||||
| Restructuring expenses | 792 | 2,733 | — | ||||||||||||||
| Employee termination benefits | 49 | 8,433 | 4,792 | ||||||||||||||
| Loss (gain) on derivative contracts | 2,251 | (5,765) | (1,094) | ||||||||||||||
| (Gain) loss on sale of assets | (18,952) | (100) | — | ||||||||||||||
| Other operating (income) expense | (382) | 306 | (608) | ||||||||||||||
| Total expenses | 54,795 | 388,483 | 713,612 | ||||||||||||||
| Income (loss) from operations | 114,087 | (273,507) | (446,767) | ||||||||||||||
| Other (expense) income | |||||||||||||||||
| Interest expense, net | (404) | (1,998) | (2,974) | ||||||||||||||
| Other (expense) income, net | 3,055 | (2,494) | 436 | ||||||||||||||
| Total other (expense) income | 2,651 | (4,492) | (2,538) | ||||||||||||||
| Income (loss) before income taxes | 116,738 | (277,999) | (449,305) | ||||||||||||||
| Income tax benefit | — | (646) | — | ||||||||||||||
| Net income (loss) | $ | 116,738 | $ | (277,353) | $ | (449,305) | |||||||||||
| Net income (loss) per share | |||||||||||||||||
| Basic | $ | 3.21 | $ | (7.77) | $ | (12.68) | |||||||||||
| Diluted | $ | 3.13 | $ | (7.77) | $ | (12.68) | |||||||||||
| Weighted average number of common shares outstanding | |||||||||||||||||
| Basic | 36,393 | 35,689 | 35,427 | ||||||||||||||
| Diluted | 37,271 | 35,689 | 35,427 | ||||||||||||||
| December 31, | December 31, | ||||||
| 2017 | 2016 | ||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
| Current liabilities | |||||||
| Accounts payable and accrued expenses | $ | 139,155 | $ | 116,517 | |||
| Derivative contracts | 10,627 | 27,538 | |||||
| Asset retirement obligations | 41,017 | 66,154 | |||||
| Other current liabilities | 8,115 | 3,497 | |||||
| Total current liabilities | 198,914 | 213,706 | |||||
| Long-term debt | 37,502 | 305,308 | |||||
| Derivative contracts | 3,568 | 2,176 | |||||
| Asset retirement obligations | 36,527 | 40,327 | |||||
| Other long-term obligations | 3,176 | 6,958 | |||||
| Total liabilities | 279,687 | 568,475 | |||||
| Commitments and contingencies (Note 15) | |||||||
| Stockholders’ Equity | |||||||
| Common stock, $0.001 par value; 250,000 shares authorized; 35,650 issued and outstanding at December 31, 2017 and 21,042 issued and 19,635 outstanding at December 31, 2016 | 36 | 20 | |||||
| Warrants | 88,500 | 88,381 | |||||
| Additional paid-in capital | 1,038,324 | 758,498 | |||||
| Accumulated deficit | (286,920 | ) | (333,982 | ) | |||
| Total stockholders’ equity | 839,940 | 512,917 | |||||
| Total liabilities and stockholders’ equity | $ | 1,119,627 | $ | 1,081,392 | |||
The accompanying notes are an integral part of these consolidated financial statements.
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of OperationsChanges in Stockholders’ Equity
| Common Stock | Warrants | Additional Paid-In Capital | Accumulated Deficit | Total | |||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | 35,687 | $ | 36 | 6,604 | $ | 88,516 | 1,055,164 | (295,995) | $ | 847,721 | |||||||||||||||||||||||||||||||
| Issuance of stock awards, net of cancellations | 40 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Common stock issued for general unsecured claims | 45 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 4,460 | — | 4,460 | ||||||||||||||||||||||||||||||||||
| Issuance of warrants for general unsecured claims | — | — | 55 | 4 | (4) | — | — | ||||||||||||||||||||||||||||||||||
| Cash paid for tax obligations on vested stock awards | — | — | — | — | (367) | — | (367) | ||||||||||||||||||||||||||||||||||
Cumulative effect of adoption of ASU 2016-02 | — | — | — | — | — | (57) | (57) | ||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | (449,305) | (449,305) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | 35,772 | 36 | 6,659 | 88,520 | 1,059,253 | (745,357) | 402,452 | ||||||||||||||||||||||||||||||||||
| Issuance of stock awards, net of cancellations | 96 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Common stock issued for general unsecured claims | 60 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 3,031 | — | 3,031 | ||||||||||||||||||||||||||||||||||
| Issuance of warrants for general unsecured claims | — | — | 75 | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Cash paid for tax obligations on vested stock awards | — | — | — | — | (64) | — | (64) | ||||||||||||||||||||||||||||||||||
| Net loss | — | — | — | — | — | (277,353) | (277,353) | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | 35,928 | 36 | 6,734 | 88,520 | 1,062,220 | (1,022,710) | 128,066 | ||||||||||||||||||||||||||||||||||
| Issuance of stock awards, net of cancellations | 547 | 1 | — | — | (1) | — | — | ||||||||||||||||||||||||||||||||||
| Common stock issued for general unsecured claims | 200 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 1,417 | — | 1,417 | ||||||||||||||||||||||||||||||||||
| Issuance of warrants for general unsecured claims | — | — | 247 | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Cash paid for tax obligations on vested stock awards | — | — | — | (899) | — | (899) | |||||||||||||||||||||||||||||||||||
| Net Income | — | — | — | — | — | 116,738 | 116,738 | ||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | 36,675 | $ | 37 | 6,981 | $ | 88,520 | $ | 1,062,737 | $ | (905,972) | $ | 245,322 | |||||||||||||||||||||||||||||
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Revenues | ||||||||||||||||
| Oil, natural gas and NGL | $ | 356,210 | $ | 98,307 | $ | 279,971 | $ | 707,434 | ||||||||
| Other | 1,089 | 149 | 13,838 | 61,275 | ||||||||||||
| Total revenues | 357,299 | 98,456 | 293,809 | 768,709 | ||||||||||||
| Expenses | ||||||||||||||||
| Production | 102,728 | 24,997 | 129,608 | 308,701 | ||||||||||||
| Production taxes | 13,644 | 2,643 | 6,107 | 15,440 | ||||||||||||
| Depreciation and depletion—oil and natural gas | 118,035 | 36,061 | 90,978 | 324,390 | ||||||||||||
| Depreciation and amortization—other | 13,852 | 3,922 | 21,323 | 47,382 | ||||||||||||
| Impairment | 4,019 | 319,087 | 718,194 | 4,534,689 | ||||||||||||
| General and administrative | 76,024 | 9,837 | 116,091 | 137,715 | ||||||||||||
| Terminated merger costs | 8,162 | — | — | — | ||||||||||||
| Employee termination benefits | 4,815 | 12,334 | 18,356 | 12,451 | ||||||||||||
| (Gain) loss on derivative contracts | (24,090 | ) | 25,652 | 4,823 | (73,061 | ) | ||||||||||
| Loss on settlement of contract | — | — | 90,184 | 50,976 | ||||||||||||
| Other operating expenses | 479 | 268 | 4,348 | 52,704 | ||||||||||||
| Total expenses | 317,668 | 434,801 | 1,200,012 | 5,411,387 | ||||||||||||
| Income (loss) from operations | 39,631 | (336,345 | ) | (906,203 | ) | (4,642,678 | ) | |||||||||
| Other (expense) income | ||||||||||||||||
| Interest expense | (3,868 | ) | (372 | ) | (126,099 | ) | (321,421 | ) | ||||||||
| Gain on extinguishment of debt | — | — | 41,179 | 641,131 | ||||||||||||
| Gain on reorganization items, net | — | — | 2,430,599 | — | ||||||||||||
| Other income, net | 2,550 | 2,744 | 1,332 | 2,040 | ||||||||||||
| Total other (expense) income | (1,318 | ) | 2,372 | 2,347,011 | 321,750 | |||||||||||
| Income (loss) before income taxes | 38,313 | (333,973 | ) | 1,440,808 | (4,320,928 | ) | ||||||||||
| Income tax (benefit) expense | (8,749 | ) | 9 | 11 | 123 | |||||||||||
| Net income (loss) | 47,062 | (333,982 | ) | 1,440,797 | (4,321,051 | ) | ||||||||||
| Less: net loss attributable to noncontrolling interest | — | — | — | (623,506 | ) | |||||||||||
| Net income (loss) attributable to SandRidge Energy, Inc. | 47,062 | (333,982 | ) | 1,440,797 | (3,697,545 | ) | ||||||||||
| Preferred stock dividends | — | — | 16,321 | 37,950 | ||||||||||||
| Income available (loss applicable) to SandRidge Energy, Inc. common stockholders | $ | 47,062 | $ | (333,982 | ) | $ | 1,424,476 | $ | (3,735,495 | ) | ||||||
| Earnings (loss) per share | ||||||||||||||||
| Basic | $ | 1.45 | $ | (17.61 | ) | $ | 2.01 | $ | (7.16 | ) | ||||||
| Diluted | $ | 1.44 | $ | (17.61 | ) | $ | 2.01 | $ | (7.16 | ) | ||||||
| Weighted average number of common shares outstanding | ||||||||||||||||
| Basic | 32,442 | 18,967 | 708,928 | 521,936 | ||||||||||||
| Diluted | 32,663 | 18,967 | 708,928 | 521,936 | ||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)Cash Flows
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | |||||||||||||||||
| Net Income (loss) | $ | 116,738 | $ | (277,353) | $ | (449,305) | |||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities | |||||||||||||||||
| Provision for doubtful accounts | (2,329) | 3,202 | 16 | ||||||||||||||
| Depreciation, depletion and amortization | 15,445 | 58,085 | 158,558 | ||||||||||||||
| Impairment | — | 256,399 | 409,574 | ||||||||||||||
| Debt issuance costs amortization | 57 | 792 | 558 | ||||||||||||||
| Write off of debt issuance costs | 174 | — | 142 | ||||||||||||||
| Loss (gain) on derivative contracts | 2,251 | (5,765) | (1,094) | ||||||||||||||
| Cash (paid) received on settlement of derivative contracts | (2,230) | 5,879 | 6,266 | ||||||||||||||
| Gain on sale of assets | (18,952) | (100) | — | ||||||||||||||
| Stock-based compensation | 1,394 | 3,012 | 4,254 | ||||||||||||||
| Other | 144 | 149 | (187) | ||||||||||||||
| Changes in operating assets and liabilities increasing (decreasing) cash | |||||||||||||||||
| Receivables | 841 | 5,867 | 15,829 | ||||||||||||||
| Prepaid expenses | 2,264 | 452 | (714) | ||||||||||||||
| Other current assets | — | 458 | (301) | ||||||||||||||
| Other assets and liabilities, net | (1,212) | 1,134 | (610) | ||||||||||||||
| Accounts payable and accrued expenses | (2,241) | (12,968) | (17,217) | ||||||||||||||
| Asset retirement obligations | (2,084) | (3,081) | (4,445) | ||||||||||||||
| Net cash provided by operating activities | 110,260 | 36,162 | 121,324 | ||||||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | |||||||||||||||||
| Capital expenditures for property, plant and equipment | (11,583) | (8,762) | (191,678) | ||||||||||||||
| Acquisitions of assets | (3,545) | (3,701) | 236 | ||||||||||||||
| Purchase of other property and equipment | (59) | — | — | ||||||||||||||
| Proceeds from sale of assets | 38,160 | 37,556 | 1,593 | ||||||||||||||
| Net cash provided by (used) in investing activities | 22,973 | 25,093 | (189,849) | ||||||||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | |||||||||||||||||
| Proceeds from borrowings | — | 59,000 | 211,096 | ||||||||||||||
| Repayments of borrowings | (20,000) | (96,500) | (153,596) | ||||||||||||||
| Debt issuance costs | (75) | (160) | (911) | ||||||||||||||
| Reduction of financing lease liability | (1,024) | (1,233) | (1,374) | ||||||||||||||
| Proceeds from exercise of stock options | 23 | — | — | ||||||||||||||
| Cash paid for tax withholding on vested stock awards | (899) | (64) | (367) | ||||||||||||||
| Net cash (used in) provided by financing activities | (21,975) | (38,957) | 54,848 | ||||||||||||||
| NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS and RESTRICTED CASH | 111,258 | 22,298 | (13,677) | ||||||||||||||
| CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year | 28,266 | 5,968 | 19,645 | ||||||||||||||
| CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year | $ | 139,524 | $ | 28,266 | $ | 5,968 | |||||||||||
Convertible Perpetual Preferred Stock | Common Stock | Additional Paid-In Capital | Treasury Stock | Accumulated Deficit | Non-controlling Interest | Total | |||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||
| Balance at December 31, 2014 - Predecessor | 5,650 | $ | 6 | 484,819 | $ | 477 | $ | 5,201,524 | $ | (6,980 | ) | $ | (3,257,202 | ) | $ | 1,271,995 | $ | 3,209,820 | |||||||||||||||
| Distributions to noncontrolling interest owners | — | — | — | — | — | — | — | (138,305 | ) | (138,305 | ) | ||||||||||||||||||||||
| Cash paid for tax withholdings on vested stock awards | — | — | — | — | (2,428 | ) | — | — | — | (2,428 | ) | ||||||||||||||||||||||
| Stock distributions, net of purchases - retirement plans | — | — | (1,000 | ) | — | (916 | ) | 1,238 | — | — | 322 | ||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 21,123 | — | — | — | 21,123 | ||||||||||||||||||||||||
| Payment received on shareholder receivable | — | — | — | — | 1,250 | — | — | — | 1,250 | ||||||||||||||||||||||||
| Issuance of restricted stock awards, net of cancellations | — | — | 1,514 | 5 | (5 | ) | — | — | — | — | |||||||||||||||||||||||
| Common stock issued for debt | — | — | 120,881 | 121 | 63,178 | — | — | 63,299 | |||||||||||||||||||||||||
| Conversion of preferred stock to common stock | (230 | ) | — | 2,968 | 3 | (3 | ) | — | — | — | — | ||||||||||||||||||||||
| Net loss | — | — | — | — | — | — | (3,697,545 | ) | (623,506 | ) | (4,321,051 | ) | |||||||||||||||||||||
| Convertible perpetual preferred stock dividends | — | — | 24,289 | 24 | 16,163 | — | (37,950 | ) | — | (21,763 | ) | ||||||||||||||||||||||
| Balance at December 31, 2015 - Predecessor | 5,420 | 6 | 633,471 | 630 | 5,299,886 | (5,742 | ) | (6,992,697 | ) | 510,184 | (1,187,733 | ) | |||||||||||||||||||||
| Cumulative effect of adoption of ASU 2015-02 | — | — | — | — | — | — | 257,081 | (510,205 | ) | (253,124 | ) | ||||||||||||||||||||||
| Cash paid for tax withholdings on vested stock awards | — | — | — | — | (44 | ) | — | — | — | (44 | ) | ||||||||||||||||||||||
| Stock distributions, net of purchases - retirement plans | — | — | 603 | — | (860 | ) | 524 | — | — | (336 | ) | ||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | 11,102 | — | — | — | 11,102 | ||||||||||||||||||||||||
| Cancellations of restricted stock awards, net of issuance | — | — | (2,184 | ) | 2 | (2 | ) | — | — | — | — | ||||||||||||||||||||||
| Common stock issued for debt | — | — | 84,390 | 84 | 4,325 | — | — | — | 4,409 | ||||||||||||||||||||||||
| Conversion of preferred stock to common stock | (173 | ) | — | 2,220 | 2 | (2 | ) | — | — | — | — | ||||||||||||||||||||||
| Net income | — | — | — | — | — | — | 1,440,797 | — | 1,440,797 | ||||||||||||||||||||||||
| Convertible perpetual preferred stock dividends | — | — | — | — | — | — | (16,321 | ) | — | (16,321 | ) | ||||||||||||||||||||||
| Balance at October 1, 2016 - Predecessor | 5,247 | 6 | 718,500 | 718 | 5,314,405 | (5,218 | ) | (5,311,140 | ) | (21 | ) | (1,250 | ) | ||||||||||||||||||||
| Cancellation of Predecessor equity | (5,247 | ) | (6 | ) | (718,500 | ) | (718 | ) | (5,314,405 | ) | 5,218 | 5,311,140 | 21 | 1,250 | |||||||||||||||||||
| Balance at October 1, 2016 - Predecessor | — | $ | — | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
66
| Common Stock | Warrants | Additional Paid-In Capital | Accumulated Deficit | Total | |||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||
| Balance at October 1, 2016 - Predecessor | — | $ | — | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||
| Issuance of Successor common stock | 18,932 | 19 | — | — | 575,144 | — | 575,163 | ||||||||||||||||||
| Issuance of Successor warrants | — | — | 6,442 | 88,382 | — | — | 88,382 | ||||||||||||||||||
| Convertible note premium | — | — | — | — | 163,879 | — | 163,879 | ||||||||||||||||||
| Balance at October 1, 2016 - Successor | 18,932 | $ | 19 | 6,442 | $ | 88,382 | $ | 739,023 | $ | — | $ | 827,424 | |||||||||||||
| Issuance of stock awards, net of cancellations | 10 | — | — | — | — | — | — | ||||||||||||||||||
| Common stock issued for debt | 693 | 1 | — | — | 13,000 | — | 13,001 | ||||||||||||||||||
| Common stock issued for warrants | — | — | — | (1 | ) | 4 | — | 3 | |||||||||||||||||
| Stock-based compensation | — | — | — | — | 6,581 | — | 6,581 | ||||||||||||||||||
| Cash paid for tax withholdings on vested stock awards | — | — | — | — | (110 | ) | — | (110 | ) | ||||||||||||||||
| Net loss | — | — | — | — | — | (333,982 | ) | (333,982 | ) | ||||||||||||||||
| Balance at December 31, 2016 - Successor | 19,635 | 20 | 6,442 | 88,381 | 758,498 | (333,982 | ) | 512,917 | |||||||||||||||||
| Issuance of stock awards, net of cancellations | 1,583 | 2 | — | — | (2 | ) | — | — | |||||||||||||||||
| Common stock issued for debt | 14,328 | 14 | — | — | 268,765 | — | 268,779 | ||||||||||||||||||
| Common stock issued for general unsecured claims | 104 | — | — | — | — | — | — | ||||||||||||||||||
| Stock-based compensation | — | — | — | — | 17,912 | — | 17,912 | ||||||||||||||||||
| Issuance of warrants for general unsecured claims | — | — | 128 | 119 | (119 | ) | — | — | |||||||||||||||||
| Cash paid for tax withholdings on vested stock awards | — | — | — | — | (6,730 | ) | — | (6,730 | ) | ||||||||||||||||
| Net income | — | — | — | — | — | 47,062 | 47,062 | ||||||||||||||||||
| Balance at December 31, 2017 - Successor | 35,650 | $ | 36 | 6,570 | $ | 88,500 | $ | 1,038,324 | $ | (286,920 | ) | $ | 839,940 | ||||||||||||
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||||||
| Net income (loss) | $ | 47,062 | $ | (333,982 | ) | $ | 1,440,797 | $ | (4,321,051 | ) | ||||||
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities | ||||||||||||||||
| Provision for doubtful accounts | 406 | (13,166 | ) | 16,704 | — | |||||||||||
| Depreciation, depletion and amortization | 131,887 | 39,983 | 112,301 | 371,772 | ||||||||||||
| Impairment | 4,019 | 319,087 | 718,194 | 4,534,689 | ||||||||||||
| Gain on reorganization items, net | — | — | (2,442,436 | ) | — | |||||||||||
| Debt issuance costs amortization | 430 | — | 4,996 | 11,884 | ||||||||||||
| Amortization of discount, net of premium, on debt | (330 | ) | (81 | ) | 2,734 | 3,130 | ||||||||||
| Gain on extinguishment of debt | — | — | (41,179 | ) | (641,131 | ) | ||||||||||
| Write off of debt issuance costs | — | — | — | 7,108 | ||||||||||||
| (Gain) loss on debt derivatives | — | — | (1,324 | ) | 10,377 | |||||||||||
| Cash paid for early conversion of convertible notes | — | — | (33,452 | ) | (32,741 | ) | ||||||||||
| (Gain) loss on derivative contracts | (24,090 | ) | 25,652 | 4,823 | (73,061 | ) | ||||||||||
| Cash received on settlement of derivative contracts | 7,260 | 7,698 | 72,608 | 327,702 | ||||||||||||
| Loss on settlement of contract | — | — | 90,184 | 50,976 | ||||||||||||
| Cash paid on settlement of contract | — | — | (11,000 | ) | (24,889 | ) | ||||||||||
| Stock-based compensation | 15,750 | 6,250 | 9,075 | 18,380 | ||||||||||||
| Other | 344 | 717 | (3,260 | ) | 2,842 | |||||||||||
| Changes in operating assets and liabilities increasing (decreasing) cash | ||||||||||||||||
| Deconsolidation of noncontrolling interest | — | — | (9,654 | ) | — | |||||||||||
| Receivables | 115 | 12,872 | 36,116 | 201,907 | ||||||||||||
| Prepaid expenses | 127 | (1,079 | ) | (5,681 | ) | 1,148 | ||||||||||
| Other current assets | 191 | (260 | ) | (181 | ) | 12,710 | ||||||||||
| Other assets and liabilities, net | 4,186 | 1,505 | (7,542 | ) | 2,239 | |||||||||||
| Accounts payable and accrued expenses | (2,199 | ) | 990 | (3,595 | ) | (86,470 | ) | |||||||||
| Asset retirement obligations | (3,979 | ) | (591 | ) | (61,305 | ) | (3,984 | ) | ||||||||
| Net cash provided by (used in) operating activities | 181,179 | 65,595 | (112,077 | ) | 373,537 | |||||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||||||
| Capital expenditures for property, plant and equipment | (219,246 | ) | (51,676 | ) | (186,452 | ) | (879,201 | ) | ||||||||
| Acquisitions of assets | (48,312 | ) | — | (1,328 | ) | (216,943 | ) | |||||||||
| Proceeds from sale of assets | 21,834 | 11,841 | 20,090 | 56,504 | ||||||||||||
| Net cash used in investing activities | (245,724 | ) | (39,835 | ) | (167,690 | ) | (1,039,640 | ) | ||||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||||||
| Proceeds from borrowings | — | — | 489,198 | 2,065,000 | ||||||||||||
| Repayments of borrowings | — | (414,954 | ) | (74,243 | ) | (939,466 | ) | |||||||||
| Debt issuance costs | (1,488 | ) | — | (333 | ) | (53,244 | ) | |||||||||
| Proceeds from building mortgage | — | — | 26,847 | — | ||||||||||||
| Payment of mortgage proceeds and cash recovery to debt holders | — | — | (33,874 | ) | — | |||||||||||
| Noncontrolling interest distributions | — | — | — | (138,305 | ) | |||||||||||
| Cash paid for tax withholdings on vested stock awards | (6,730 | ) | (110 | ) | (44 | ) | (3,535 | ) | ||||||||
| Dividends paid—preferred | — | — | — | (11,262 | ) | |||||||||||
| Other | — | 3 | — | 1,250 | ||||||||||||
| Net cash (used in) provided by financing activities | (8,218 | ) | (415,061 | ) | 407,551 | 920,438 | ||||||||||
| NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH | (72,763 | ) | (389,301 | ) | 127,784 | 254,335 | ||||||||||
| CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year | 174,071 | 563,372 | 435,588 | 181,253 | ||||||||||||
| CASH, CASH EQUIVALENTS and RESTRICTED CASH end of year | $ | 101,308 | $ | 174,071 | $ | 563,372 | $ | 435,588 | ||||||||
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | |||||
| Enterprise value | $ | 1,089,808 | ||
| Plus: Cash and cash equivalents | 563,372 | |||
| Less: Fair value of Building Note | (36,610 | ) | ||
| Less: Asset retirement obligation | (92,412 | ) | ||
| Less: Fair value of First Lien Exit Facility | (414,954 | ) | ||
| Less: Fair value of Convertible Notes | (445,660 | ) | ||
| Less: Fair value of warrants, including warrants held in reserve for settlement of general unsecured claims | (95,794 | ) | ||
| Fair value of Successor common stock issued upon emergence | $ | 567,750 | ||
| Shares issued upon emergence on October 4, 2016, including shares held in reserve for settlement of general unsecured claims | 19,371 | |||
| Per share value | $ | 29.31 | ||
| Enterprise value | $ | 1,089,808 | ||
| Plus: cash and cash equivalents | 563,372 | |||
| Plus: other working capital liabilities | 131,766 | |||
| Plus: other long-term liabilities | 8,549 | |||
| Reorganization value of Successor assets | $ | 1,793,495 | ||
| Predecessor Company | Reorganization Adjustments | Fresh Start Adjustments | Successor Company | ||||||||||||
| ASSETS | |||||||||||||||
| Current assets | |||||||||||||||
| Cash and cash equivalents | $ | 652,680 | $ | (142,148 | ) | (1) | $ | — | $ | 510,532 | |||||
| Restricted cash - collateral | — | 50,000 | (2) | — | 50,000 | ||||||||||
| Restricted cash - other | — | 2,840 | (2) | — | 2,840 | ||||||||||
| Accounts receivable, net | 61,446 | 12,356 | (3) | — | 73,802 | ||||||||||
| Derivative contracts | 10,192 | — | (669 | ) | (12) | 9,523 | |||||||||
| Prepaid expenses | 12,514 | (8,218 | ) | (4) | — | 4,296 | |||||||||
| Other current assets | 1,003 | — | 3,217 | (13) | 4,220 | ||||||||||
| Total current assets | 737,835 | (85,170 | ) | 2,548 | 655,213 | ||||||||||
| Oil and natural gas properties, using full cost method of accounting | |||||||||||||||
| Proved | 12,093,492 | — | (11,344,684 | ) | (14) | 748,808 | |||||||||
| Unproved | 322,580 | — | (205,578 | ) | (14) | 117,002 | |||||||||
| Less: accumulated depreciation, depletion and impairment | (11,637,538 | ) | — | 11,637,538 | (14) | — | |||||||||
| 778,534 | — | 87,276 | 865,810 | ||||||||||||
| Other property, plant and equipment, net | 357,528 | (41 | ) | (93,782 | ) | (15) | 263,705 | ||||||||
| Derivative contracts | 70 | — | (70 | ) | (12) | — | |||||||||
| Other assets | 12,537 | (3,770 | ) | (5) | — | 8,767 | |||||||||
| Total assets | $ | 1,886,504 | $ | (88,981 | ) | $ | (4,028 | ) | $ | 1,793,495 | |||||
| Predecessor Company | Reorganization Adjustments | Fresh Start Adjustments | Successor Company | ||||||||||||
| LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY | |||||||||||||||
| Current liabilities | |||||||||||||||
| Accounts payable and accrued expenses | $ | 140,448 | $ | (14,820 | ) | (6) | $ | — | $ | 125,628 | |||||
| Derivative contracts | 2,982 | — | 1,666 | (12) | 4,648 | ||||||||||
| Asset retirement obligations | 8,573 | — | 57,105 | (16) | 65,678 | ||||||||||
| Total current liabilities | 152,003 | (14,820 | ) | 58,771 | 195,954 | ||||||||||
| Long-term debt | — | 731,735 | (7) | 1,610 | (17) | 733,345 | |||||||||
| Derivative contracts | 935 | — | 304 | (12) | 1,239 | ||||||||||
| Asset retirement obligations | 62,896 | — | (36,161 | ) | (16) | 26,735 | |||||||||
| Other long-term obligations | 3 | 8,798 | (8) | (3 | ) | 8,798 | |||||||||
| Liabilities subject to compromise | 4,346,188 | (4,346,188 | ) | (9) | — | — | |||||||||
| Total liabilities | 4,562,025 | (3,620,475 | ) | 24,521 | 966,071 | ||||||||||
| Equity | |||||||||||||||
| SandRidge Energy, Inc. stockholders’ equity (deficit) | |||||||||||||||
| Predecessor preferred stock | 6 | — | (6 | ) | (18) | — | |||||||||
| Predecessor common stock | 718 | — | (718 | ) | (18) | — | |||||||||
| Predecessor additional paid-in capital | 5,315,655 | — | (5,315,655 | ) | (18) | — | |||||||||
| Predecessor additional paid-in capital—stockholder receivable | (1,250 | ) | 1,250 | (10) | — | — | |||||||||
| Predecessor treasury stock, at cost | (5,218 | ) | — | 5,218 | (18) | — | |||||||||
| Successor common stock | — | 19 | (11) | — | 19 | ||||||||||
| Successor warrants | — | 88,382 | (11) | — | 88,382 | ||||||||||
| Successor additional paid-in capital | — | 739,023 | (11) | — | 739,023 | ||||||||||
| Accumulated deficit | (7,985,411 | ) | 2,702,820 | (9) | 5,282,591 | (19) | — | ||||||||
| Total SandRidge Energy, Inc. stockholders’ (deficit) equity | (2,675,500 | ) | 3,531,494 | (28,570 | ) | 827,424 | |||||||||
| Noncontrolling interest | (21 | ) | — | 21 | (20) | — | |||||||||
| Total stockholders’ (deficit) equity | (2,675,521 | ) | 3,531,494 | (28,549 | ) | 827,424 | |||||||||
| Total liabilities and stockholders’ equity (deficit) | $ | 1,886,504 | $ | (88,981 | ) | $ | (4,028 | ) | $ | 1,793,495 | |||||
| 1. |
| Sources: | ||||
| Proceeds from Building Note | $ | 26,847 | ||
| Total sources | $ | 26,847 | ||
| Uses and transfers: | ||||
| Cash transferred to restricted accounts (collateral and general unsecured claims) | $ | 52,840 | ||
| Payments and funding of escrow account related to professional fees | 43,770 | |||
| Payment on Senior Credit facility (principal and interest) | 35,238 | |||
| Repayment of Senior Secured Notes and Unsecured Notes | 33,874 | |||
Payment of certain contract cures and other | 3,273 | |||
| Total uses and transfers | 168,995 | |||
| Net uses and transfers | $ | (142,148 | ) | |
| Current maturities of long-term debt and accrued interest | $ | 4,179,483 | ||
| Accounts payable and accrued expenses | 157,422 | |||
| Other long-term liabilities | 9,283 | |||
| Liabilities subject to compromise of the Predecessor | 4,346,188 | |||
| Cash payments at emergence | (72,385 | ) | ||
| Cash proceeds from building mortgage | 26,847 | |||
| Write-off of prepaid accounts upon emergence | (8,218 | ) | ||
| Accrual for future reimbursement from professional fees escrow account and other receivables | 12,356 | |||
| Total consideration given pursuant to the Plan: | ||||
| Fair value of equity issued | (827,424 | ) | ||
| Principal value of long-term debt issued and reinstated at emergence | (731,735 | ) | ||
| Reinstatement of liabilities subject to compromise as accounts payable and accrued expenses | (37,789 | ) | ||
| Release of stockholder receivable | (1,250 | ) | ||
| Application of deposit held by utility services | (3,770 | ) | ||
| Gain on settlement of liabilities subject to compromise | $ | 2,702,820 | ||
| Par value of 18.9 million shares of Common Stock issued to former holders of the Senior Secured Notes and Unsecured Notes (valued at $29.31 per share) | $ | 19 | ||
| Fair value of warrants issued to holders of the Unsecured Notes(1) | 88,382 | |||
| Additional paid in capital - Common Stock | 575,144 | |||
| Additional paid in capital - premium on Convertible Notes(2) | 163,879 | |||
| Total Successor Company equity issued on Emergence Date | $ | 827,424 | ||
| Unamortized long-term debt | $ | 3,546,847 | ||
| Litigation claims | (20,478 | ) | ||
| Rejections and cures of executory contracts | (16,038 | ) | ||
| Ad valorem and franchise taxes | (3,494 | ) | ||
| Legal and professional fees and expenses | (44,920 | ) | ||
| Write off of director and officer insurance policy | (7,533 | ) | ||
| Gain on accounts payable settlements | 84,228 | |||
| Loss on mortgage | (8,153 | ) | ||
| Gain on preferred stock dividends | 37,893 | |||
| Fresh start valuation adjustments | (28,549 | ) | ||
| Fair value of equity issued | (827,424 | ) | ||
| Principal value of Convertible Notes issued | (281,780 | ) | ||
| Gain on reorganization items, net | $ | 2,430,599 | ||
Nature of Business. SandRidge Energy, Inc. is an oil and natural gas acquisition, development and production company headquartered in Oklahoma City, Oklahoma with a principal focus on explorationdeveloping and production activitiesproducing hydrocarbon resources in the Mid-Continent and North Park Basin regions of the United States. The Company’s North Park Basin properties were acquired during the fourth quarter of 2015.
Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. During the year ended December 31, 2015, the Company fully consolidated the activities of each the SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Mississippian Trust II (the “Mississippian Trust II”) and SandRidge Permian Trust (the “Permian Trust”) (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) as variable interest entities for which the Company was the primary beneficiary. Activitiessubsidiaries, including its proportionate share of the Royalty Trusts attributable to third party ownership were presented as noncontrolling interest and included as a component of equity in the condensed consolidated balance sheet as of December 31, 2015. As discussed further below, during the years ended December 31, 2017, and December 31, 2016, the Company proportionately consolidated the activities of the Royalty Trusts.Trust. All significant intercompany accounts and transactions have been eliminated in consolidation.
Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.
The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and natural gas liquids (“NGL”)NGL reserves; impairment tests of long-lived assets; the carrying value of unevaluatedunproved oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; valuation allowances for deferred tax assets; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.significantly from those estimates.
Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.
Restricted Cash. The Company maintains restricted escrow funds as required by certain contractual arrangements in accordance with the Plan. In addition, the Company maintains funds related to collateralize letters of credit and credit cards issued by lenders that were party to the 2017 Credit Facility.
Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the exploration,drilling, completion, and production and treating services forof oil and natural gas, which have a contractual maturity of one year or less. An allowance for doubtful accounts has been established based on management’s review of the collectibilitycollectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. As part of fresh start accounting, the allowance for doubtful accounts was reset to zero on the Emergence Date. Refer to Note 85 for further information on the Company’s accounts receivable and allowance for doubtful accounts.
Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, restricted cash, trade receivables, prepaid expenses, and trade payables and long-term debt.accrued expenses. The carrying valuevalues of cash, trade receivables and trade payables are considered to be representative of their respectivereflect fair values due to the short-term maturity of these instruments. See Note 74 for further discussion of the Company’s fair value measurements.
Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows, or third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Fair value measurements for the electrical asset were based on replacement cost. Inputs used in the cost approach are based on the cost to a market participant buyer to acquire or construct a substitute asset of comparable utility, adjusted for inutility. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 7.
Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, theThe Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing orto manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market conditions.conditions, planned capital expenditures, and any debt service requirements when determining whether to enter into oil and gas derivative contracts. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates.
The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met.instrument. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings.guidance. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 136 for further discussion of the Company’s derivatives.
Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, explorationdevelopment, and developmentproduction activities and capitalized interest. The Successor Company capitalized gross internal costs of $14.8$0.5 million, $0.7 million and $4.0$5.7 million during the yearyears ended December 31, 20172021, 2020 and the Successor 2016 Period, respectively, and the Predecessor Company capitalized internal costs of $22.7 million and $45.1 million to the full cost pool during the Predecessor 2016 Period and the year ended December 31, 2015,2019, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by
multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
Costs associated with unproved properties are excluded from the amortizable cost base until a determinationit has been made as to the existence ofdetermined that proved reserves.reserves exist or a lease is impaired. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and thereby, subjected to amortization.amortized. The costs associated with unproved properties relateare primarily tothe costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value.impairment. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development ifwhether the proved reserves are assigned.can be developed economically. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.
Under the full cost method of accounting, total capitalized costs of oil and natural gas properties and electrical infrastructure assets, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”).ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation is exceeded, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.
The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and asSEC prices adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”).reserves. If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows.hedges. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.center, unless it results in a greater than 10% change to the depletion rate.
Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, electrical infrastructure, transportation equipment and other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost.cost or fair value established on the Emergence Date less applicable depreciation. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 107 to 39 years for buildings and 21 to 3027 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. As part of fresh start accounting, property, plant and equipment were adjusted to their estimated fair value and depreciable lives were revised as of October 1, 2016, as described in Note 2.
Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value if any, is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 109 for further discussion of impairments.
Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During the year ended December 31, 2017 and the Successor 2016 Period, the Company did not capitalize any interest costs. During the Predecessor 2016 Period and the year ended December 31, 2015,2021 the Company capitalized interest of approximately $2.2$0.3 million and $10.8 million, respectively, on unproved properties that
were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally,During the Predecessoryear ended December 31, 2020 the Company capitalized interest of $3.3approximately $0.7 million on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in 2015 on midstream and corporate assets which were under construction.progress.
Debt Issuance Costs. The Company includes unamortized line-of-credit debt issuance costs, if any, related to its credit facility2020 Credit Facility in other assets in the consolidated balance sheets. Other debt issuance costs related to long-term debt, if any, are presented in the balance sheets as a direct deduction from the associated debt liability.liability, if material. Debt issuance costs are amortized to interest expense over the scheduled maturity periodterm of the related debt. Upon retirement ofWhen debt is retired, any unamortized costs, if material are written off and included in the determination of the gain or loss on extinguishment of debt.
Asset Retirement Obligations. The Company owns oil and natural gas propertiesassets that require expenditures to plug, abandon and remediate wellsassociated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded inat the period in which the liability is incurred (atestimated present value at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception,acquired, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the wellasset is sold at which timeand the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. 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. See Note 1412 for further discussion of the Company’s asset retirement obligations. As part of fresh start accounting, the ARO liabilities were adjusted to their estimated fair value as described in Note 2.
Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded at a point in time when titlecontrol of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company has made an accounting policy election to deductdeducts transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $29.1 million and $7.4 million of transportation costs as a reduction from revenues in the year ended December 31, 2017 and the Successor 2016 Period, respectively, versus the presentation of $26.2 million and $45.3 million, respectively, of these costs as production expenses in the Predecessor 2016 Period and the year ended December 31, 2015, respectively. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production, tax expensead valorem and other taxes in the consolidated statements of operations. See Note 16 for further information on the Company's accounting policies related to revenues.
The Company accounts for natural gas production imbalances using the sales method, whereby itwhich recognizes revenue on all natural gas sold to its customers notwithstandingeven though the fact that its ownershipnatural gas volumes sold may be more or less than the natural gas sold.Company's ownership entitles it to sell. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $1.6$1.4 million and $1.7$1.1 million at
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
December 31, 20172021 and 2016,2020, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.
Allocation of Share-Based Compensation. For both the Successor and Predecessor Companies, equityEquity compensation provided to employees directly involved in explorationproduction and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, and other operating expense in the accompanying consolidated statements of operations.
Restructuring expenses. Restructuring expenses represent fees and costs associated with our outsourcing and relocation of certain corporate specific functions that are of a non-recurring nature, and expenses related to the 2016 bankruptcy.
Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.
The Company has elected an accounting policy in which interest and penalties on income taxes resulting from the underpayment or late payment of income taxes due to a taxing authority or relating to income tax contingencies are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.
Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the Successor Company consist of unvested restricted stock awards, performance share units, warrants, and warrants,stock options using the treasury method, and convertible senior notes, using the if-converted method. Potentially dilutive securities for the Predecessor Company consist of unvested restricted stock awards and restricted share units, using the treasury method, and convertible preferred stock and convertible senior notes, using the if-converted method.
Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants or the proceeds that would be received if the warrants were exercised are assumed to be used to repurchase shares at the average market price.
Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 1513 for discussion of the Company’s commitments and contingencies.
Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market, which involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its commodity derivative counterparties on an ongoing basis and considers its counterparties’their credit default risk ratings in determining the fair value of its commodity derivative contracts. TheHistorically, the Company’s commodity derivative contracts arehave been with multiple counterparties to minimize its exposure to any individual counterparty.
The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
owners in the property for their share of those costs. The Company’s joint interest partners consistare primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.
The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
| Sales | % of Revenue | ||||||||||
| December 31, 2021 | |||||||||||
| Targa Pipeline Mid-Continent West OK LLC | $ | 91,066 | 53.9 | % | |||||||
| Plains Marketing, L.P. | $ | 51,204 | 30.3 | % | |||||||
| December 31, 2020 | |||||||||||
| Plains Marketing, L.P. | $ | 40,058 | 34.8 | % | |||||||
| Targa Pipeline Mid-Continent West OK LLC | $ | 38,287 | 33.3 | % | |||||||
| Sinclair Crude Company | $ | 36,375 | 31.6 | % | |||||||
| December 31, 2019 | |||||||||||
| Targa Pipeline Mid-Continent West OK LLC | $ | 85,780 | 32.1 | % | |||||||
| Sinclair Crude Company | $ | 74,810 | 28.0 | % | |||||||
| Plains Marketing, L.P. | $ | 69,214 | 25.9 | % | |||||||
| Sales | % of Revenue | |||||
| December 31, 2017 - Successor | ||||||
| Targa Pipeline Mid-Continent West OK LLC | $ | 144,583 | 40.5 | % | ||
| Plains Marketing, L.P. | $ | 117,927 | 33.0 | % | ||
| Period from October 2, 2016 through December 31, 2016 - Successor | ||||||
| Targa Pipeline Mid-Continent West OK LLC | $ | 35,845 | 36.4 | % | ||
| Plains Marketing, L.P. | $ | 32,022 | 32.5 | % | ||
| Period from January 1, 2016 through October 1, 2016 - Predecessor | ||||||
| Plains Marketing, L.P. | $ | 110,370 | 37.6 | % | ||
| Targa Pipeline Mid-Continent West OK LLC | $ | 108,238 | 36.8 | % | ||
| December 31, 2015 - Predecessor | ||||||
| Plains Marketing, L.P. | $ | 318,018 | 41.4 | % | ||
| Targa Pipeline Mid-Continent West OK LLC | $ | 231,649 | 30.1 | % | ||
certain other instruments that are not measured at fair value through net income. The standard replaced the previously required incurred loss approach with the objective of reducing the existing diversity in practice of classification on certain cash receipts and payments in the statement of cash flows.an expected loss model for instruments measured at amortized cost. The guidance requires adoption by application of a retrospective method to each period presented. The amendments are effective for the Company adopted this ASU on January 1, 2018,2020 using a modified retrospective approach; however, the impact was not material upon adoption.
ASU 2019-12 - In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” which simplifies various aspects of accounting for income taxes, including requirements related to hybrid tax regimes, the tax basis step-up in goodwill obtained in a transaction that is not a business combination, separate financial statements of entities not subject to tax, the intraperiod tax allocation exception to the incremental approach, ownership changes in investments, interim-period accounting for enacted changes in tax laws, and year-to-date loss limitation in interim-period tax accounting. The standard is effective for interim and annual periods beginning after December 15, 2020, with early adoption permitted. The Company adopted the ASU
permitted, and will be applied on April 1, 2017. The guidance had no impact on the consolidated financial statements and related disclosures.
Recent Accounting Pronouncements Not Yet Adopted. TheASU 2020-04 - In March 2020, FASB issued ASU 2016-02, “LeasesNo. 2020-04, Reference Rate Reform (Topic 842)848),” which requires companies to recognizefacilitate the assets and liabilities for the rights and obligationseffects of all leases with a term greater than 12 months (long-term)reference rate reform on the balance sheet. Leases to explore for or use minerals, oil and natural gas are not impacted by this guidance. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842.”financial reporting. This ASU permitsprovides optional practical expedients and exceptions for applying United States Generally Accepted Accounting Principles ("US GAAP") provisions to contracts, hedging relationships, and other transactions that reference LIBOR, or other reference rates expected to be discontinued because of reference rate reform, if certain criteria are met. The provisions of this ASU do not apply to contract modifications made and hedging transactions entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, that an entity to continue to apply its current accounting policyhas elected certain optional expedients for land easementsand that existed beforeare retained through the effective dateend of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements to determine whether the arrangement contains a lease. Topic 842 requires adoption by application of a modified retrospective transition approach and ishedging relationship. The amendments in ASU 2020-04 are effective, for the Company on January 1, 2019. Early adoption is permitted.
all entities, as of March 12, 2020 through December 31, 2022. The Company is incurrently reviewing the processpotential impact of reviewingthe upcoming LIBOR
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
reference rate change on its portfolio of leased assetscurrent contracts and related contracts tohedging relationships and will determine the impact that adoption will have on its consolidated financial statements and related disclosures. The Company is also assessing the impactapplicable provisions of Topic 842 on its systems, processes and internal controls. The Company plans to elect certain practical expedients when implementing the new lease standard, which means the Company will not have to reassess the existence or classification of leases for contracts, including land easements, that commenced prior to adoption. The Company anticipates upon adoption to recognize assets and liabilities for the rights and obligations of its existing long-term operating leases on its consolidated balance sheets and to utilize new systems, processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases after the date of adoption. The Company will complete its evaluation during 2018 and will adopt Topic 842 on January 1, 2019, using a modified retrospective approach for all comparative periods presented.ASU 2020-04.
Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Supplemental Disclosure of Cash Flow Information | |||||||||||||||||
| Cash paid for interest, net of amounts capitalized | $ | (177) | $ | (1,260) | $ | (2,157) | |||||||||||
| Cash received for income taxes | $ | — | $ | 616 | $ | — | |||||||||||
| Supplemental Disclosure of Noncash Investing and Financing Activities | |||||||||||||||||
| Purchase of PP&E in accounts payable | $ | 1,029 | $ | 396 | $ | 4,592 | |||||||||||
| Right-of-use assets obtained in exchange for financing lease obligations | $ | 1,258 | $ | 67 | $ | 3,347 | |||||||||||
| Carrying value of properties exchanged | $ | — | $ | 3,890 | $ | 5,384 | |||||||||||
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Supplemental Disclosure of Cash Flow Information | ||||||||||||||||
| Cash paid for reorganization items | $ | — | $ | — | $ | (55,606 | ) | $ | — | |||||||
| Cash paid for interest, net of amounts capitalized | $ | (2,438 | ) | $ | (1,183 | ) | $ | (104,609 | ) | $ | (296,386 | ) | ||||
| Cash (paid) received for income taxes | $ | 4,348 | $ | — | $ | (28 | ) | $ | (88 | ) | ||||||
| Supplemental Disclosure of Noncash Investing and Financing Activities | ||||||||||||||||
| Cumulative effect of adoption of ASU 2015-02 | $ | — | $ | — | $ | (247,566 | ) | $ | — | |||||||
| Property, plant and equipment transferred in settlement of contract | $ | — | $ | — | $ | 215,635 | $ | — | ||||||||
| Change in accrued capital expenditures | $ | (28,999 | ) | $ | 10,630 | $ | 25,045 | $ | 177,586 | |||||||
| Equity issued for debt | $ | (268,779 | ) | $ | (13,001 | ) | $ | (4,409 | ) | $ | (63,299 | ) | ||||
| Preferred stock dividends paid in common stock | $ | — | $ | — | $ | — | $ | (16,188 | ) | |||||||
| Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement | $ | — | $ | — | $ | — | $ | (50,310 | ) | |||||||
North Park Basin Sale
On February 10, 2017,5, 2021, the Company acquired assets consisting of approximately 13,000 net
On September 10, 2020, the Company acquired all of the assetsoverriding royalty interests held by SandRidge Mississippian Royalty Trust II ("the Trust") for a net purchase price of $3.3 million, given our 37.6% ownership of the Trust. The Company accounted for this transaction as an asset acquisition and terminated a gathering agreementallocated 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. See Note 9 for additional discussion on the sale of the building.
2019 Acquisitions and Divestitures
Nonmonetary transaction. During the third quarter of 2019, the Company transferred its interest in certain proved oil and natural gas properties located in Comanche, Harper and Sumner counties in Kansas along with PGC for $48.0 million in cashassociated electrical
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
infrastructure and $78.0 million principalan insignificant amount of newly issued PGC Senior Secured Notes. PGC owned approximately 370 milesaccounts receivable with an aggregate estimated fair value of gathering lines supporting the$5.4 million, for an interest in certain other proved oil and natural gas production from the Company's Piñon fieldproperties located in the WTO. The transaction resultedComanche, Harper and Barber counties in the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume.Kansas. The fair value of the consideration paid byassets given in the Company, including discount attributable to the PGC Senior Secured Notes,transaction approximated their carrying value, therefore no gain or loss was approximately $98.3 million and was allocated on a fair value basis between the assets acquired (approximately $47.3 million) and a lossrecognized on the termination of the gathering contract (approximately $51.0 million).transfer.
The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, certain other current and non-current assets, accounts payable and accrued expenses and other current liabilities and other long-term obligations included in the unaudited condensed consolidated balance sheets approximated fair value at December 31, 2017,2021 and there were no open derivative contracts at December 31, 2016.2020. Additionally, the carrying amount of debt associated with borrowings outstanding under the 2020 Credit Facility approximated fair value as borrowings bear interest at variable rates. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment and related impairments, which are calculated using Level 3 inputs, are discussed in Note 9.
| Level 1 | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. | |||||||
| Level 2 | Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. | |||||||
| Level 3 | Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity). | |||||||
Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’sCompany's financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in Level 1 and Level 2 of the hierarchy as of December 31, 2017 and 2016,2021, as described below.
Level 2 Fair Value Measurements
Commodity Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model or option pricing model using the applicable inputs discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates.
| Unobservable Input | Range | Weighted Average | Fair Value | ||||||||||
| (In thousands) | |||||||||||||
| Debt conversion feature hazard rate | 114.0 | % | – | 135.2 | % | 119.2 | % | $ | 29,355 | ||||
Fair Value - Recurring Measurement Basis
The following tables summarizetable summarizes the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):
There were no open commodity derivatives contracts as of December 31, 2017 - Successor2020.
| Fair Value Measurements | Netting(1) | Assets/Liabilities at Fair Value | |||||||||||||||||
| Level 1 | Level 2 | Level 3 | |||||||||||||||||
| Assets | |||||||||||||||||||
| Commodity derivative contracts | $ | — | $ | 5,582 | $ | — | $ | (4,272 | ) | $ | 1,310 | ||||||||
| Investments | $ | 5,072 | $ | — | $ | — | $ | — | $ | 5,072 | |||||||||
| $ | 5,072 | $ | 5,582 | $ | — | $ | (4,272 | ) | $ | 6,382 | |||||||||
| Liabilities | |||||||||||||||||||
| Commodity derivative contracts | $ | — | $ | 18,467 | $ | — | $ | (4,272 | ) | $ | 14,195 | ||||||||
| $ | — | $ | 18,467 | $ | — | $ | (4,272 | ) | $ | 14,195 | |||||||||
| Fair Value Measurements | Netting(1) | Assets/Liabilities at Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||
| Fair Value Measurements | Netting(1) | Assets/Liabilities at Fair Value | ||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | ||||||||||||||||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||||||||||||||||||
| Investments | $ | 7,541 | $ | — | $ | — | $ | — | $ | 7,541 | ||||||||||||||||||||||||||||||||||||||
| $ | 7,541 | $ | — | $ | — | $ | — | $ | 7,541 | Level 1 | Level 2 | Level 3 | Netting(1) | Assets/Liabilities at Fair Value | ||||||||||||||||||||||||||||||||||
| Liabilities | Liabilities | |||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivative contracts | $ | — | $ | 29,714 | $ | — | $ | — | $ | 29,714 | Commodity derivative contracts | $ | — | $ | 200 | $ | — | $ | 179 | $ | 21 | |||||||||||||||||||||||||||
| $ | — | $ | 29,714 | $ | — | $ | — | $ | 29,714 | |||||||||||||||||||||||||||||||||||||||
| Total | Total | $ | — | $ | 200 | $ | — | $ | 179 | $ | 21 | |||||||||||||||||||||||||||||||||||||
____________________
(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
| Predecessor | ||||
| Period from January 1, 2016 through October 1, 2016 | ||||
| Beginning balance | $ | 29,355 | ||
| Gain on derivative holder conversion feature | (880 | ) | ||
| Conversions | (21,194 | ) | ||
| Write off of derivative holder conversion feature to reorganization items | (7,281 | ) | ||
| Ending level 3 debt holder conversion feature balance | $ | — | ||
Transfers. Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the years ended December 31, 2017, 20162021, 2020 and 2015,2019, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.
| December 31, 2017 | December 31, 2016 | ||||||||||||||
| Fair Value | Carrying Value | Fair Value | Carrying Value | ||||||||||||
| Convertible Notes | $ | — | $ | — | $ | 334,800 | $ | 268,780 | |||||||
| Building Note | $ | 42,526 | $ | 37,502 | $ | 40,608 | $ | 36,528 | |||||||
Fair Value of Non-Financial Assets and Liabilities
See Note 2 for additional information regarding fair value adjustments for non-financial assets and liabilities resulting from the application of fresh start accounting and Note 109 for discussion of the Company’s impairment valuations.
A summary of accounts receivable is as follows (in thousands):
| December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Oil, natural gas and NGL sales | $ | 18,829 | $ | 12,757 | |||||||
| Joint interest billing | 3,441 | 6,421 | |||||||||
| Other | 1,262 | 4,754 | |||||||||
| Total accounts receivable | 23,532 | 23,932 | |||||||||
| Less: allowance for doubtful accounts | (2,027) | (4,356) | |||||||||
| Total accounts receivable, net | $ | 21,505 | $ | 19,576 | |||||||
| December 31, | |||||||
| 2017 | 2016 | ||||||
| Oil, natural gas and NGL sales | $ | 34,570 | $ | 42,631 | |||
| Joint interest billing | 26,496 | 17,338 | |||||
| Oil and natural gas services | 639 | 736 | |||||
| Other | 10,846 | 14,272 | |||||
| Total accounts receivable | 72,551 | 74,977 | |||||
| Less: allowance for doubtful accounts | (1,274 | ) | (880 | ) | |||
| Total accounts receivable, net | $ | 71,277 | $ | 74,097 | |||
The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2021 and 2020 (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | ||||||||||||||||
| Beginning balance | $ | 4,356 | $ | 1,117 | |||||||||||||
| Additions charged to costs and expenses (1) | 21 | 3,239 | |||||||||||||||
| Deductions (2) | (2,350) | — | |||||||||||||||
| Ending balance | $ | 2,027 | $ | 4,356 | |||||||||||||
____________________
(1)The Company performed an assessment of receivable balances related to governmental and other regulatory items during the year ended December 31, 2017,2020, and recorded a $2.5 million allowance that is non-recurring in nature. The assessment was almost entirely reversed in the Successor 2016 Period,amount of $2.4 million during the Predecessor 2016 Periodsecond half of 2021.
(2)Deductions represent collections of amounts for which an allowance had previously been established.
6. Derivatives
Commodity Derivatives
The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. On occasion, the Company has attempted to manage this risk on a portion of its forecasted oil or natural gas production sales through the use of commodity derivative contracts.
The Company has not designated any of its derivative contracts as hedges for accounting purposes. All derivative contracts are recorded at fair value with changes in derivative contract fair values recognized as gain or loss on derivative contracts in the consolidated statements of operations. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Commodity derivative contracts are settled on a monthly basis, and the commodity derivative contract valuations are adjusted to the mark-to-market valuation on a quarterly basis.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
The following table summarizes derivative activity for the years ended December 31, 2021, 2020 and 2019 (in thousands):
| Year Ended December 31, | |||||||||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||||||||
| Loss (gain) on commodity derivative contracts | $ | 2,251 | $ | (5,765) | $ | (1,094) | |||||||||||||||||
| Cash paid (received) on settlements | $ | 2,230 | $ | (5,879) | $ | (6,266) | |||||||||||||||||
Master Netting Agreements and the Right of Offset. As applicable, the Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis by commodity type in the consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of December 31, 2021, the counterparties to the Company’s open commodity derivative contracts consisted of 1 financial institution.
The following table summarizes (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions as of December 31, 2021 and no open positions as of December 31, 2020 (in thousands):
December 31, 2021
| Gross Amounts | Gross Amounts Offset | Amounts Net of Offset | Financial Collateral | Net Amount | ||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Derivative contracts - current | $ | 200 | $ | 179 | $ | 21 | $ | — | $ | 21 | ||||||||||||||||||||||
| Total | $ | 200 | $ | 179 | $ | 21 | $ | — | $ | 21 | ||||||||||||||||||||||
As of 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:
| Notional | Units | Weighted Average Fixed Price per Unit | ||||||||||||||||||
| NGL Price Swaps: January 2022 - February 2022 | 1,042,000 | Gallons | $ | 1.20 | ||||||||||||||||
| Natural Gas Price Swaps: January 2022 - February 2022 | 720,000 | MMBtu | $ | 4.07 | ||||||||||||||||
Because we did not designate any of our derivative contracts as hedges for accounting purposes, changes in the fair value of our derivative contracts were recognized as gains and losses in current period earnings. As a result, and as applicable, our current period earnings could have been significantly affected by changes in the fair value of our commodity derivative
contracts. Changes in fair value were principally measured based on a comparison of future prices to the contract price at the
end of the period.
Fair Value of Derivatives
The following table presents the fair value of the Company’s derivative contracts on a net basis with same counterparty netting (in thousands):
| December 31, | ||||||||||||||
| Type of Contract | Balance Sheet Classification | 2021 | ||||||||||||
| Derivative liabilities | ||||||||||||||
| Natural Gas and NGL price swaps | Derivative - Current liabilities | $ | 21 | |||||||||||
See Note 4 for additional discussion of the fair value measurement of the Company’s derivative contracts.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
7. Leases
The Company determines if an arrangement is or contains a lease at inception. A lease is defined as a contract, or part of a contract, that conveys the right to control the use of identified property, plant or equipment for a period of time in exchange for consideration. As most of the Company's leases do not provide an implicit rate, the Company's incremental borrowing rate was used as the discount rate when determining the present value of future payments. Lease assets are recognized based on the lease liability plus any prepaid lease payments and excluding lease incentives and initial direct costs incurred for the same periods. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that option will be exercised. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.
Operating leases are included in other assets, other current liabilities and other long-term obligations, and finance leases are included in other property, plant and equipment, other current liabilities and other long-term obligations on the accompanying consolidated balance sheet as of December 31, 2021 and 2020.
The Company had operating and financing leases for vehicles and equipment outstanding during the year ended December 31, 2021 and 2020, which were not significant to the consolidated financial statements.
The components of lease costs recognized for the Company's right-of-use leases are shown below (in thousands):
| Year Ended December 31, 2021 | Year Ended December 31, 2020 | Year Ended December 31, 2019 | ||||||||||||||||||
| Short-term lease cost (1) | $ | 892 | $ | 1,880 | $ | 9,994 | ||||||||||||||
| Financing lease cost | 389 | 1,220 | 1,397 | |||||||||||||||||
| Operating lease cost | 151 | 169 | 188 | |||||||||||||||||
| Total lease cost | $ | 1,432 | $ | 3,269 | $ | 11,579 | ||||||||||||||
___________________
(1)There were no short-term lease costs capitalized as part of oil and natural gas properties during the year ended December 31, 2021 and 2020, and $4.8 million in 2019. Portions of these costs were reimbursed to the Company by other working interest owners.
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Beginning balance | $ | 880 | $ | — | $ | 4,847 | $ | 7,083 | ||||||||
| Additions charged to costs and expenses(1) | 397 | 880 | 16,695 | 1,320 | ||||||||||||
| Deductions(2) | (3 | ) | — | (751 | ) | (3,556 | ) | |||||||||
| Impact of fresh start accounting | — | — | (20,791 | ) | — | |||||||||||
| Ending balance | $ | 1,274 | $ | 880 | $ | — | $ | 4,847 | ||||||||
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Property, plant and equipment consists of the following (in thousands):
| December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Oil and natural gas properties | |||||||||||
| Proved | $ | 1,454,016 | $ | 1,463,950 | |||||||
| Unproved | 12,255 | 17,964 | |||||||||
| Total oil and natural gas properties | 1,466,271 | 1,481,914 | |||||||||
| Less accumulated depreciation, depletion and impairment | (1,373,217) | (1,375,692) | |||||||||
| Net oil and natural gas properties capitalized costs | 93,054 | 106,222 | |||||||||
| Land | 200 | 200 | |||||||||
| Electrical infrastructure | 121,819 | 121,819 | |||||||||
| Non-oil and natural gas equipment | 1,575 | 1,563 | |||||||||
| Buildings and structures | 3,603 | 3,603 | |||||||||
| Financing Leases | 1,384 | 1,051 | |||||||||
| Total | 128,581 | 128,236 | |||||||||
| Less accumulated depreciation and amortization | (30,790) | (25,118) | |||||||||
| Other property, plant and equipment, net | 97,791 | 103,118 | |||||||||
| Total property, plant and equipment, net | $ | 190,845 | $ | 209,340 | |||||||
| December 31, | |||||||
| 2017 | 2016 | ||||||
| Oil and natural gas properties | |||||||
| Proved | $ | 1,056,806 | $ | 840,201 | |||
| Unproved | 100,884 | 74,937 | |||||
| Total oil and natural gas properties | 1,157,690 | 915,138 | |||||
| Less accumulated depreciation, depletion and impairment | (460,431 | ) | (353,030 | ) | |||
| Net oil and natural gas properties capitalized costs | 697,259 | 562,108 | |||||
| Land | 4,500 | 5,100 | |||||
| Electrical infrastructure | 131,010 | 130,242 | |||||
| Non-oil and natural gas equipment | 26,809 | 35,768 | |||||
| Buildings and structures | 79,548 | 88,603 | |||||
| Total | 241,867 | 259,713 | |||||
| Less accumulated depreciation and amortization | (15,886 | ) | (3,889 | ) | |||
| Other property, plant and equipment, net | 225,981 | 255,824 | |||||
| Total property, plant and equipment, net | $ | 923,240 | $ | 817,932 | |||
The average rates used for depreciation and depletion of oil and natural gas properties were $7.92$0.78 per Boe in 2017, $8.31 per Boe for the Successor 2016 Period, $6.052021, $5.11 per Boe in the Predecessor 2016 Period2020 and $10.81$12.28 per Boe in 2019.
Costs Excluded from Amortization
The following table summarizes the costs by year incurred,excluded from amortization was related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2017 (in thousands):2021 and 2020 were $12.3 million and $18.0 million, respectively.
| Year Cost Incurred | |||||||||||||||||||
| Total | 2017 | 2016 | 2015 | 2014 and Prior | |||||||||||||||
| Property acquisition | $ | 96,450 | $ | 42,827 | $ | 15,610 | $ | 19,481 | $ | 18,532 | |||||||||
| Exploration | 4,434 | 1,904 | 678 | 1,453 | 399 | ||||||||||||||
| Total costs incurred | $ | 100,884 | $ | 44,731 | $ | 16,288 | $ | 20,934 | $ | 18,931 | |||||||||
The Company assesses the need to impair its oil and 2015, thegas properties during its quarterly full cost pool ceiling limitation calculation. The Company analyzedanalyzes various property, plant and equipment for impairment when certain triggering events occur by comparing the carrying values of thesethe assets to their estimated fair values. EstimatedThe full cost pool ceiling limitation and estimated fair values of drilling, midstream, electrical transmission and other assets were determined in accordance with the policies discussed in Note 3.1.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
Impairment for the years ended December 31, 2021, 2020 and 2019 consists of the following (in thousands):
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Full cost pool ceiling limitation | $ | — | $ | 218,399 | $ | 409,574 | ||||||||||||||
| Other | — | 38,000 | — | |||||||||||||||||
| $ | — | $ | 256,399 | $ | 409,574 | |||||||||||||||
| Successor | Predecessor | ||||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | ||||||||||||||
| Full cost pool ceiling limitation(1)(2) | $ | — | $ | 319,087 | $ | 657,392 | $ | 4,473,787 | |||||||||
| Drilling assets(3)(4) | 4,019 | — | 3,511 | 37,646 | |||||||||||||
| Electrical infrastructure assets(5) | — | — | 55,600 | — | |||||||||||||
| Midstream assets(6) | — | — | 1,691 | 7,148 | |||||||||||||
| Other(7) | — | — | — | 16,108 | |||||||||||||
| $ | 4,019 | $ | 319,087 | $ | 718,194 | $ | 4,534,689 | ||||||||||
The asset impairment charge of $38.0 million recorded for the year ended December 31, 2020 resulted from the write down of the net carrying amount of the office headquarters building assets to their estimated fair value less estimated costs to sell the building. In May 2020, the Company entered into an agreement for the sale of its corporate headquarters building located in Oklahoma City, OK. The building sale closed on August 31, 2020.
In accordance with the applicable accounting guidance, FASB ASC 360-10-45-9, the Company reclassified its corporate headquarters building net carrying amount from Other property, plant and equipment, net, to Assets held for sale on the Consolidated Balance Sheet at June 30, 2020. The Company also reclassified the liabilities associated with the corporate headquarters building from Accounts payable and accrued expenses to Liabilities held for sale on the Consolidated Balance Sheet at June 30, 2020. Further, The Company recorded an impairment charge of $38.0 million in the three-month period ended June 30, 2020 to write down the net carrying amount of the office headquarters building assets to their estimated fair value less estimated costs to sell the building. No impairment charges were recorded for the corporate headquarters building assets for the year ended December 31, 2019.
Prior to the sale of the corporate headquarters building, the carrying amount of the building was assessed for recoverability and impairment using undiscounted cash flow measures of the consolidated Company as prescribed under ASC 360-10-35, rather than fair value as prescribed under ASC 360-10-45-9.
10. Accounts Payable and Accrued Expenses
Accounts payable and accrued expenses consist of the following (in thousands):
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Accounts payable and other accrued expenses | $ | 13,727 | $ | 23,017 | ||||||||||
| Production payable | 23,974 | 15,367 | ||||||||||||
| Payroll and benefits | 3,942 | 5,640 | ||||||||||||
| Taxes payable | 3,902 | 6,864 | ||||||||||||
| Drilling advances | 234 | 477 | ||||||||||||
| Accrued interest | — | 61 | ||||||||||||
| Total accounts payable and accrued expenses | $ | 45,779 | $ | 51,426 | ||||||||||
| December 31, | |||||||
| 2017 | 2016 | ||||||
| Accounts payable and other accrued expenses | $ | 94,406 | $ | 65,408 | |||
| Accrued interest | 1,385 | 648 | |||||
| Production payable | 18,059 | 16,011 | |||||
| Payroll and benefits | 21,475 | 33,606 | |||||
| Drilling advances | 3,830 | 844 | |||||
| Total accounts payable and accrued expenses | $ | 139,155 | $ | 116,517 | |||
78
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
11. Long-Term Debt
Long-term debt consists of the following (in thousands):
| December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| 2020 Credit Facility - Term Loan | $ | — | $ | 20,000 | |||||||
| Long-term debt | $ | — | $ | 20,000 | |||||||
| December 31, | December 31, | ||||||
| 2017 | 2016 | ||||||
| Credit facility | $ | — | $ | — | |||
| Convertible Notes | — | 268,780 | |||||
| Building Note | 37,502 | 36,528 | |||||
| Total debt | 37,502 | 305,308 | |||||
| Less: current maturities of long-term debt | — | — | |||||
| Long-term debt | $ | 37,502 | $ | 305,308 | |||
Credit Facility. On February 10, 2017, the $425.0 million reserve-based revolving credit facility (the “First Lien Exit Facility”) was refinanced and replaced by a new $600.0 million credit facility (the “credit facility”). The borrowing base under the credit facility is $425.0 million. This borrowing base was reconfirmed during the October 2017 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, 2018. The credit facility matures on March 31, 2020. The outstanding borrowings under the credit facility bear interest based on a pricing grid tied to borrowing base utilization of (a) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (b) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum. Interest on base rate borrowings is payable quarterly in arrears and interest on LIBOR borrowings is payable every one, two, three or six months, at the election of the Company. Quarterly, the Company pays commitment fees assessed at annual rates of 0.50% on any available portion of the credit facility. The Company has the right to prepay loans under the credit facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans. Upon refinancing of the First Lien Exit Facility, $50.0 million maintained in a restricted cash collateral account, as required by the terms of the First Lien Exit Facility, was released to the Company.
The borrowing base under2020 Credit Facility replaced the First Lien ExitCompany’s 2017 Credit Facility, was $425.0 million. The First Lien Exit Facility was set to mature on February 4, 2020. The outstanding borrowings under the First Lien Exit Facility bore interest at a rate equal to, at the option of the Company, either (a) a base rate plus an applicable rate of 3.75% per annum or (b) LIBOR plus 4.75% per annum, subject to a 1.00% LIBOR floor. Interest on base rate borrowings was payable quarterly in arrears and interest on LIBOR borrowings was payable every one, two, three or six months, at the election of the Company. Quarterly, the Company was committed to pay fees assessed at annual rates of 0.50% on any available portion of the First Lien Exit Facility. The Company had the right to prepay loans under the First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans.
On September 2, 2021, the Company repaid its $20.0 million, term loan in full and terminated all commitments and obligations under the 2020 Credit Facility. The Company’s board of directors in good faith that: (a) the refinancing provided for terms that were materially more favorablepayment to the Company and (b) causing a conversion was notLender under the primary purpose of the refinancing.
At December 31, 2017, the Company’s commodity derivative contracts consisted of fixed price swaps under which2021, the Company receives a fixed price for the contractdid not have any term or revolving debt obligations and pays a floating market price to the counterparty over a specified period for a contracted volume.
During the year ended December 31, 2015,2021, the Companyweighted average interest rate paid for borrowings outstanding under the 2020 Credit Facility was party to derivatives agreements withapproximately 2.6%. During the Mississippian Trust I, Permian Trust and Mississippian Trust II to provide each ofyear ended December 31, 2020, the Royalty Trusts withweighted average interest rate paid for borrowings outstanding under both the economic effect of certain oil and natural gas derivative contracts entered into by the Company with third parties. The derivatives agreements with the Mississippian Trust Ioutstanding 2017 Credit Facility and the Mississippian Trust II contained commodity derivative contracts that covered volumes of oil and natural gas production through December 31, 2015, and the derivatives agreement with the Permian Trust contained commodity derivative contracts that covered volumes of oil production through March 31, 2015. All activity related to the contracts underlying the derivatives agreements with the Royalty Trusts have been included in the Company’s consolidated derivative disclosures.2020 Credit Facility was approximately 3.2%.
During the year ended December 31, 2021, the Company paid a related party, an affiliate of Icahn Enterprises,$0.4 million of interest expense which is included on the Interest expense, net line item on the Consolidated Statement of Operations. During the year ended December 31, 2020, the Company paid a related party, an affiliate of Icahn Enterprises, an immaterial amount of loss under commodity derivative transactions due to credit riskinterest expense which is limited toincluded on the Interest expense, net amounts due from its counterparties. Asline item on the Consolidated Statement of December 31, 2017, the counterparties to the Company’s open commodity derivative contracts consisted of seven financial institutions, all of which are also lenders under the Company’s credit facility.Operations. The Company is not required to post additional collateral under its commodity derivative contracts as alltotal outstanding balance of the counterparties to2020 Credit facility is recorded in long-term debt on the Company’s commodity derivative contracts share in the collateral supporting the Company’s credit facility.
| Gross Amounts | Gross Amounts Offset | Amounts Net of Offset | Financial Collateral | Net Amount | ||||||||||||||||
| Assets | ||||||||||||||||||||
| Derivative contracts - current | $ | 5,582 | $ | (4,272 | ) | $ | 1,310 | $ | — | $ | 1,310 | |||||||||
| Derivative contracts - noncurrent | — | — | — | — | — | |||||||||||||||
| Total | $ | 5,582 | $ | (4,272 | ) | $ | 1,310 | $ | — | $ | 1,310 | |||||||||
| Liabilities | ||||||||||||||||||||
| Derivative contracts - current | $ | 14,899 | $ | (4,272 | ) | $ | 10,627 | $ | (10,627 | ) | $ | — | ||||||||
| Derivative contracts - noncurrent | 3,568 | — | 3,568 | (3,568 | ) | — | ||||||||||||||
| Total | $ | 18,467 | $ | (4,272 | ) | $ | 14,195 | $ | (14,195 | ) | $ | — | ||||||||
| Gross Amounts | Gross Amounts Offset | Amounts Net of Offset | Financial Collateral | Net Amount | ||||||||||||||||
| Liabilities | ||||||||||||||||||||
| Derivative contracts - current | $ | 27,538 | $ | — | $ | 27,538 | $ | (27,538 | ) | $ | — | |||||||||
| Derivative contracts - noncurrent | 2,176 | — | 2,176 | (2,176 | ) | — | ||||||||||||||
| Total | $ | 29,714 | $ | — | $ | 29,714 | $ | (29,714 | ) | $ | — | |||||||||
| Notional (MBbls) | Weighted Average Fixed Price | |||||
| January 2018 - December 2018 | 3,464 | $ | 55.08 | |||
| January 2019 - December 2019 | 1,460 | $ | 53.34 | |||
| Notional (MMcf) | Weighted Average Fixed Price | |||||
| January 2018 - December 2018 | 17,300 | $ | 3.16 | |||
| December 31, | December 31, | |||||||||
| Type of Contract | Balance Sheet Classification | 2017 | 2016 | |||||||
| Derivative assets | ||||||||||
| Oil price swaps | Derivative contracts - current | $ | — | $ | — | |||||
| Natural gas price swaps | Derivative contracts - current | 5,582 | — | |||||||
| Oil price swaps | Derivative contracts - noncurrent | — | — | |||||||
| Natural gas price swaps | Derivative contracts - noncurrent | — | — | |||||||
| Derivative liabilities | ||||||||||
| Oil price swaps | Derivative contracts - current | (14,899 | ) | (13,395 | ) | |||||
| Natural gas price swaps | Derivative contracts - current | — | (14,143 | ) | ||||||
| Oil price swaps | Derivative contracts - noncurrent | (3,568 | ) | (2,105 | ) | |||||
| Natural gas price swaps | Derivative contracts - noncurrent | — | (71 | ) | ||||||
| Total net derivative contracts | $ | (12,885 | ) | $ | (29,714 | ) | ||||
79
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands):
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Beginning balance | $ | 106,481 | $ | 92,413 | $ | 103,578 | $ | 54,402 | ||||||||
| Liability incurred upon acquiring and drilling wells | 1,336 | 121 | 505 | 1,662 | ||||||||||||
| Revisions in estimated cash flows(1) | (28,565 | ) | 12,397 | — | 44,060 | |||||||||||
| Liability settled or disposed in current period(2) | (11,308 | ) | (540 | ) | (36,979 | ) | (1,023 | ) | ||||||||
| Accretion | 9,600 | 2,090 | 4,365 | 4,477 | ||||||||||||
| Impact of fresh start accounting | — | — | 20,944 | — | ||||||||||||
| Ending balance | 77,544 | 106,481 | 92,413 | 103,578 | ||||||||||||
| Less: current portion | 41,017 | 66,154 | 65,678 | 8,399 | ||||||||||||
| Asset retirement obligations, net of current | $ | 36,527 | $ | 40,327 | $ | 26,735 | $ | 95,179 | ||||||||
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Beginning balance | $ | 57,168 | $ | 75,016 | $ | 60,064 | |||||||||||
| Liability incurred upon acquiring and drilling wells | 18 | 309 | 2,771 | ||||||||||||||
| Revisions in estimated cash flows (1) | 6,800 | (17,192) | 12,208 | ||||||||||||||
| Liability settled or disposed in current period (2) | (8,668) | (6,866) | (5,379) | ||||||||||||||
| Accretion (3) | 4,050 | 5,901 | 5,352 | ||||||||||||||
| Ending balance | 59,368 | 57,168 | 75,016 | ||||||||||||||
| Less: current portion | 17,606 | 16,467 | 22,119 | ||||||||||||||
| Asset retirement obligations, net of current | $ | 41,762 | $ | 40,701 | $ | 52,897 | |||||||||||
____________________
Legal Proceedings. As previously disclosed, on May 16, 2016, and 2015. Employee termination benefits were $4.8 million for the year ended December 31, 2017, $12.3 million for the Successor 2016 Period and $18.4 million for the Predecessor 2016 Period, primarily as a result of reductions in workforce. For the year ended December 31, 2015, employee termination benefits were $12.5 million, primarily as a result of a reduction in workforceCompany and certain executives’ separation from employment.
Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated cases (the “Cases”):
• In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma against(“In re SandRidge ExplorationEnergy, Inc. Securities Litigation”); and Production, LLC, among other defendants.
• Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge
Mississippian Trust I, et al., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma (“Lanier Trust”)
The lead plaintiffs in both In their amended complaint, plaintiffs assertedre SandRidge Energy, Inc. Securities Litigation and Lanier Trust assert claims on behalf of themselves and (i) in In re SandRidge Energy, Inc. Securities Litigation, a class of all purchasers of SandRidge common stock from February 24, 2011 and November 8, 2012 under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, and (ii) in Lanier Trust, a putative class of purchasers of SandRidge Mississippian Trust I and SandRidge Mississippian Trust II common units between April 7, 2011 and November 8, 2012 under Sections 11, 12(a)(2), and 15 of the Securities Act of 1933 and Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder, both based on allegations that defendants, which include certain former officers of the Company and the SandRidge Mississippian Trust I, made misrepresentations or omissions concerning various tort claims seeking relief for damages,topics including the reimbursementperformance of past and future earthquake insurance premiums, resulting from seismic activity allegedly causedwells operated by the defendants’ operation of wastewater disposal wells. The court dismissed the plaintiffs’ amended complaint on May 12, 2017, but permitted the plaintiffs to file a second amended complaint. On July 18, 2017, the plaintiffs filed a second amended class action complaint making allegations substantially similar to those containedCompany in the amended complaint that was previously dismissed. AnMississippian region.
80
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
In each of the Cases, lead plaintiffs seek to recover unspecified damages, interest, costs and expenses incurred in the litigation on behalf of themselves and class members. Although the claims against the Company in each Case have been discharged pursuant to the Plan, the Company remains a nominal defendant. The Company may also be contractually obligated to indemnify two former officers who are defendants and the SandRidge Mississippian Trust I against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses, which it is required to advance, arising out of the Cases, although the Company disputes any such obligations. Such indemnification is not covered by insurance with respect to the Trust. As of October 2020, we have exhausted all remaining insurance coverage for the costs of indemnification and expect no further reimbursements.
In light of the status of the Cases, and the facts, circumstances and legal theories relating thereto, the Company is not able to determine the likelihood of an outcome in either case or provide an estimate of any reasonably possible loss or range of possible loss related thereto. However, considering the exhaustion of insurance coverage available to the Company, such losses, associated with this action can notif incurred, could be made at this time.material. The Company has not established any reservesliabilities relating to this action.the Cases and believes that the plaintiffs’ claims are without merit. The Company intends to continue to vigorously defend against the Cases in its capacity as a nominal defendant.
In addition to the mattermatters described above, the Company is involved in various lawsuits, claims and proceedings, which are being handled and defended by the Company in the ordinary course of business.
| Successor | ||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | |||||||
| Number of shares withheld for taxes | 349 | 5 | ||||||
| Value of shares withheld for taxes | $ | 6,730 | $ | 110 | ||||
| Convertible Perpetual Preferred Stock | ||||||||
| 8.5% | 7.0% | |||||||
| Liquidation preference per share | $ | 100.00 | $ | 100.00 | ||||
| Annual dividend per share | $ | 8.50 | $ | 7.00 | ||||
| Conversion rate per share to common stock | 12.4805 | 12.8791 | ||||||
| Predecessor | ||||||||
| Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||
| 8.5% Convertible perpetual preferred stock | ||||||||
| Dividends paid in cash | $ | — | $ | 11,262 | ||||
| Dividends satisfied in shares of common stock(1) | $ | — | $ | 11,262 | ||||
| Accrued dividends at period end | $ | — | $ | 8,447 | ||||
| Dividends in arrears | $ | 11,262 | $ | — | ||||
| 7.0% Convertible perpetual preferred stock | ||||||||
| Dividends paid in cash | $ | — | $ | — | ||||
| Dividends satisfied in shares of common stock(2) | $ | — | $ | 10,500 | ||||
| Accrued dividends at period end | $ | — | $ | 13,125 | ||||
| Dividends in arrears | $ | 21,000 | $ | 10,500 | ||||
| Predecessor | ||||||||||||
| Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | Year Ended December 31, 2014 | ||||||||||
| Number of shares withheld for taxes | 1,122 | 1,872 | 1,034 | |||||||||
| Value of shares withheld for taxes | $ | 44 | $ | 2,428 | $ | 6,373 | ||||||
Number of Shares | Weighted- Average Grant Date Fair Value | |||||
| (In thousands) | ||||||
| Unvested restricted shares outstanding at October 1, 2016 | — | $ | — | |||
| Granted | 1,448 | $ | 24.32 | |||
| Vested | (14 | ) | $ | 24.32 | ||
| Forfeited / Canceled | (27 | ) | $ | 24.32 | ||
| Unvested restricted shares outstanding at December 31, 2016 | 1,407 | $ | 24.32 | |||
| Granted | 671 | $ | 19.97 | |||
| Vested | (827 | ) | $ | 23.23 | ||
| Forfeited / Canceled | (146 | ) | $ | 23.52 | ||
| Unvested restricted shares outstanding at December 31, 2017 | 1,105 | $ | 22.62 | |||
Number of Shares | Weighted- Average Grant Date Fair Value | |||||
| (In thousands) | ||||||
| Unvested restricted shares outstanding at December 31, 2014 | 8,556 | $ | 6.39 | |||
| Granted | 2,928 | $ | 0.88 | |||
| Vested | (5,186 | ) | $ | 4.95 | ||
| Forfeited / Canceled | (672 | ) | $ | 6.38 | ||
| Unvested restricted shares outstanding at December 31, 2015 | 5,626 | $ | 4.85 | |||
| Granted | — | $ | — | |||
| Vested | (3,034 | ) | $ | 5.34 | ||
| Forfeited / Canceled | (2,592 | ) | $ | 4.31 | ||
| Predecessor ending unvested restricted shares at October 1, 2016 | — | $ | — | |||
The Company’s income tax (benefit) provision consisted of the following components (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Current | |||||||||||||||||
| Federal | $ | — | $ | (646) | $ | — | |||||||||||
| State | — | — | — | ||||||||||||||
| — | (646) | — | |||||||||||||||
| Deferred | |||||||||||||||||
| Federal | — | — | — | ||||||||||||||
| State | — | — | — | ||||||||||||||
| — | — | — | |||||||||||||||
| Total (benefit) provision | $ | — | $ | (646) | $ | — | |||||||||||
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Current | ||||||||||||||||
| Federal | $ | (8,719 | ) | $ | — | $ | — | $ | — | |||||||
| State | (30 | ) | 9 | 11 | 123 | |||||||||||
| (8,749 | ) | 9 | 11 | 123 | ||||||||||||
| Deferred | ||||||||||||||||
| Federal | — | — | — | — | ||||||||||||
| State | — | — | — | — | ||||||||||||
| — | — | — | — | |||||||||||||
| Total (benefit) provision | (8,749 | ) | 9 | 11 | 123 | |||||||||||
| Less: income tax provision attributable to noncontrolling interest | — | — | — | 90 | ||||||||||||
| Total (benefit) provision attributable to SandRidge Energy, Inc. | $ | (8,749 | ) | $ | 9 | $ | 11 | $ | 33 | |||||||
A reconciliation of the (benefit) provision for income taxes at the statutory federal tax rate to the Company’s actual income tax (benefit) provision is as follows (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Computed at federal statutory rate | $ | 24,404 | $ | (58,574) | $ | (94,354) | |||||||||||
| State taxes, net of federal benefit | 3,012 | (10,898) | (20,500) | ||||||||||||||
| Non-deductible expenses | 83 | 18 | 137 | ||||||||||||||
| Stock-based compensation | (541) | 643 | 602 | ||||||||||||||
| Return to provision adjustments | (221) | (945) | (6,096) | ||||||||||||||
| Refund of AMT Sequestration | — | (646) | — | ||||||||||||||
| Change in valuation allowance | (26,733) | 69,285 | 120,211 | ||||||||||||||
| Other | (4) | 471 | — | ||||||||||||||
| Total (benefit) provision | $ | — | $ | (646) | $ | — | |||||||||||
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Computed at federal statutory rate | $ | 13,409 | $ | (116,891 | ) | $ | 504,283 | $ | (1,512,325 | ) | ||||||
| State taxes, net of federal benefit | (284 | ) | (3,696 | ) | 10,512 | (19,988 | ) | |||||||||
| Non-deductible expenses | 1,711 | 144 | 462 | 816 | ||||||||||||
| Non-deductible debt costs | — | — | 22,694 | 10,228 | ||||||||||||
| Stock-based compensation | 1,109 | 306 | 5,884 | 6,700 | ||||||||||||
| Net effects of consolidating the non-controlling interests’ tax provisions | — | — | — | 218,196 | ||||||||||||
| Discharge of debt and other reorganization related items | 1,018 | — | 359,278 | — | ||||||||||||
| Return to provision adjustments (1) | 341,681 | — | — | — | ||||||||||||
| Impact of legislative changes | 243,801 | — | — | — | ||||||||||||
| Release of valuation allowance | (8,719 | ) | — | — | — | |||||||||||
| Change in valuation allowance | (602,452 | ) | 120,144 | (903,102 | ) | 1,296,405 | ||||||||||
| Other | (23 | ) | 2 | — | 1 | |||||||||||
| Total (benefit) provision attributable to SandRidge Energy, Inc. | $ | (8,749 | ) | $ | 9 | $ | 11 | $ | 33 | |||||||
81
Notes to | ||||||||
Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. The Company’s deferred tax assets have been reduced by a valuation allowance due to a determination made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. During the year ended December 31, 2017, the Company reduced the valuation allowance associated with deferred tax assets
Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):
| December 31, 2017 | December 31, 2016 | ||||||
| Deferred tax liabilities | |||||||
| Investments(1) | $ | 171,517 | $ | 275,128 | |||
| Total deferred tax liabilities | 171,517 | 275,128 | |||||
| Deferred tax assets | |||||||
| Property, plant and equipment | 391,273 | 751,683 | |||||
| Derivative contracts | 3,131 | 11,274 | |||||
| Allowance for doubtful accounts | 986 | 1,487 | |||||
| Net operating loss carryforwards | 217,259 | 527,079 | |||||
| Compensation and benefits | 5,700 | 14,494 | |||||
| Tax Credits and other carryforwards | 33,001 | 43,770 | |||||
| Asset retirement obligations | 18,843 | 40,399 | |||||
| Other | 2,273 | 4,663 | |||||
| Total deferred tax assets | 672,466 | 1,394,849 | |||||
| Valuation allowance | (500,949 | ) | (1,119,721 | ) | |||
| Net deferred tax liability | $ | — | $ | — | |||
| December 31, 2021 | December 31, 2020 | |||||||||||||
| Deferred tax liabilities | ||||||||||||||
| Investments (1) | $ | — | $ | 34,816 | ||||||||||
| Derivative contracts | — | — | ||||||||||||
| Total deferred tax liabilities | — | 34,816 | ||||||||||||
| Deferred tax assets | ||||||||||||||
| Property, plant and equipment | 181,037 | 317,063 | ||||||||||||
| Net operating loss carryforwards | 440,332 | 365,772 | ||||||||||||
| Tax credits and other carryforwards | 33,861 | 33,538 | ||||||||||||
| Asset retirement obligations | 14,842 | 15,216 | ||||||||||||
| Investments (1) | 106 | — | ||||||||||||
| Other | 2,363 | 2,500 | ||||||||||||
| Total deferred tax assets | 672,541 | 734,089 | ||||||||||||
| Valuation allowance | (672,541) | (699,273) | ||||||||||||
| Net deferred tax liability | $ | — | $ | — | ||||||||||
____________________
(1) Includes the Company’s deferred tax liability resulting from its investment |
As of December 31, 2017,2021, the Company had approximately $4.7 million of alternative minimum tax credits available that do not expire. However, due to a special tax election available, the AMT credits are reflected as a current receivable as of December 31, 2017. In addition, the Company had approximately $805.3 million$1.7 billion of federal net operating loss carryovers,NOL carryforwards, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation, thatlimitation. Of the $1.7 billion of federal NOL carryforwards, $0.8 billion expire during the years 2025 through 2037.
The Company did not have unrecognized tax benefits is as follows (in thousands):
| Successor | Predecessor | |||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | ||||||||||
| Unrecognized tax benefit at January 1 | $ | 84 | $ | 81 | $ | 81 | ||||||
| Changes to unrecognized tax benefits related to a prior period | 2 | 3 | — | |||||||||
| Lapse of statute of limitations | (38 | ) | — | — | ||||||||
| Unrecognized tax benefit at December 31 | $ | 48 | $ | 84 | $ | 81 | ||||||
The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 20142017 to present remain open for federal examination. Additionally, tax years 2005 through 20132016 remain subject to examination for the purpose of determining the amount of federal net operating lossNOL and other carryforwards. The number of years open for state tax audits varies, depending on the state, but is generally from three to five years.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
15. Equity
Common Stock and Performance Share Units. At December 31, 2021, the Company had 36.7 million shares of common stock, par value $0.001 per share, issued and outstanding, including 0.1 million shares of unvested restricted stock awards, and 250.0 million shares of common stock authorized. The Company also has 0.4 million of restricted stock units, an immaterial amount of performance share units and 0.3 million stock options outstanding at December 31, 2021 as discussed further in Note 17.
Warrants. Since the fourth quarter of 2016, the Company has issued approximately 4.9 million Series A warrants and 2.1 million Series B warrants to certain holders of general unsecured claims as defined in the 2016 bankruptcy reorganization plan. These warrants are exercisable until October 4, 2022 for 1 share of common stock per warrant at initial exercise prices of $41.34 and $42.03 per share, respectively, subject to adjustments pursuant to the terms of the warrants. The warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions.
Share Repurchase Program. 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.
The Tax Benefits Preservation Plan. On July 1, 2020, the Board declared a dividend distribution of 1 right (a “Right”) for each outstanding share of Company common stock, par value $0.001 per share to stockholders of record at the close of business on July 13, 2020. Each Right entitles its holder, under certain circumstances, to purchase from the Company one one-thousandth of a share of Series A Junior Participating Preferred Stock of the Company, par value $0.001 per share, at an exercise price of $5.00 per Right, subject to adjustment. The description and terms of the Rights are set forth in the tax benefits preservation plan, dated as of July 1, 2020, between the Company and American Stock Transfer & Trust Company, LLC, as rights agent (and any successor rights agent, the “Rights Agent”).
The Company adopted the Tax Benefits Preservation Plan, as amended on March 16, 2021, in order to protect shareholder value against a possible limitation on the Company’s ability to use its tax net operating losses (the “NOLs”) and certain other tax benefits to reduce potential future U.S. federal income tax obligations. The NOLs are a valuable asset to the Company, which may inure to the benefit of the Company and its stockholders. However, if the Company experiences an “ownership change,” as defined in Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), its ability to fully utilize the NOLs and certain other tax benefits will be substantially limited and the timing of the usage of the NOLs and such other benefits could be substantially delayed, which could significantly impair the value of those assets. 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 Code) 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. The Tax Benefits Preservation Plan is intended to prevent against such an “ownership change” by deterring any person or group from acquiring beneficial ownership of 4.9% or more of the Company’s securities.
Subject to certain exceptions, the Rights become exercisable and trade separately from Common Stock only upon the “Distribution Time,” which occurs upon the earlier of:
•the close of business on the tenth (10th) day after the “Stock Acquisition Date,” which is (a) the first date of public announcement that a person or group of affiliated or associated persons (with certain exceptions, an “Acquiring Person”) has acquired, or obtained the right or obligation to acquire, beneficial ownership of 4.9% or more of the outstanding shares of Common Stock (with certain exceptions) or (b) such other date, as determined by the Board, on which a person or group has become an Acquiring Person, or
•the close of business on the tenth (10th) business day (or later date as may be determined by the Board prior to such time as any person or group becomes an Acquiring Person) following the commencement of a tender offer or exchange offer which, if consummated, would result in a person or group becoming an Acquiring Person.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
Any existing stockholder or group that beneficially owns 4.9% or more of Common Stock has been grandfathered at its current ownership level, but the Rights will not be exercisable if, at any time after the announcement of the Tax Benefits Preservation Plan, such stockholder or group increases its ownership of Common Stock by one share of Common Stock. Certain synthetic interests in securities created by derivative positions, whether or not such interests are considered to be ownership of the underlying Common Stock or are reportable for purposes of Regulation 13D of the Securities Exchange Act of 1934, as amended, are treated as beneficial ownership of the number of shares of Common Stock equivalent to the economic exposure created by the derivative position, to the extent actual shares of Common Stock are directly or indirectly held by counterparties to the derivatives contracts.
Until the earlier of the Distribution Time and the Expiration Time, the surrender for transfer of any shares of Common Stock will also constitute the transfer of the Rights associated with those shares. As soon as practicable after the Distribution Time, separate rights certificates will be mailed to holders of record of Common Stock as of the close of business on the Distribution Time. From and after the Distribution Time, the separate rights certificates alone will represent the Rights. Except as otherwise provided in the Tax Benefits Preservation Plan, only shares of Common Stock issued prior to the Distribution Time will be issued with Rights. The Rights are not exercisable until the Distribution Time.
The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021.
In the event that any person or group (other than certain exempt persons) becomes an Acquiring Person (a “Flip-in Event”), each holder of a Right (other than any Acquiring Person and certain related parties, whose Rights automatically become null and void) will have the right to receive, upon exercise, shares of Common Stock having a value equal to two times the exercise price of the Right.
In the event that, at any time following the Stock Acquisition Date, any of the following occurs (each, a “Flip-over Event”):
•the Company consolidates with, or merges with and into, any other entity, and the Company is not the continuing or surviving entity
•any entity engages in a share exchange with or consolidates with, or merges with or into, the Company, and the Company is the continuing or surviving entity and, in connection with such share exchange, consolidation or merger, all or part of the outstanding shares of Common Stock are changed into or exchanged for stock or other securities of any other entity or cash or any other property; or
•the Company sells or otherwise transfers, in one transaction or a series of related transactions, fifty percent (50%) or more of the Company’s assets, cash flow or earning power, each holder of a Right (except Rights which previously have been voided as described above) will have the right to receive, upon exercise, common stock of the acquiring company having a value equal to two times the exercise price of the Right.
Shares Withheld for Taxes. The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired.
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Number of shares withheld for taxes | 192 | 51 | 56 | |||||||||||||||||
| Value of shares withheld for taxes | $ | 899 | $ | 64 | $ | 367 | ||||||||||||||
16. Revenues
The following table disaggregates the Company’s revenue by source for the years ended December 31, 2021, 2020 and 2019 (in thousands):
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
Oil (1) | $ | 62,297 | $ | 73,621 | $ | 186,360 | ||||||||||||||
| NGL | 50,836 | 17,962 | 35,598 | |||||||||||||||||
| Natural gas | 55,749 | 22,867 | 44,146 | |||||||||||||||||
| Other | — | 526 | 741 | |||||||||||||||||
| Total revenues | $ | 168,882 | $ | 114,976 | $ | 266,845 | ||||||||||||||
(1) Results include revenue from NPB from 2019 through February 5, 2021, the closing date of the NPB sale.
Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs. In accordance with the contracts governing these sales, performance obligations to customers are satisfied and revenues are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis.
Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production, ad valorem, and other taxes expense in the consolidated statements of operations.
Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of December 31, 2021 and 2020, the Company had revenues receivable of $18.8 million and $12.8 million., respectively, and we did not record any bad debt expense on revenues receivable December 31, 2021 and 2020.
17. Share-Based Compensation
Share-Based Compensation
Omnibus Incentive Plan. The Omnibus Incentive Plan became effective on October 4, 2016 and authorizes the issuance of up to 4.6 million shares of SandRidge common stock.
Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of common stock, as well as certain cash-based awards. At December 31, 2021, the Company had restricted stock awards, restricted stock units, performance share units and stock options outstanding under the Omnibus Incentive Plan. Forfeitures for these awards are recognized as they occur.
Restricted Stock Awards. The Company’s restricted stock awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Outstanding restricted shares at December 31, 2021 will generally vest over either a one-year period or three-year period with a remaining weighted average contractual period of 0.4 years and have $0.1 million of associated unrecognized compensation cost.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
The following table presents a summary of the Company’s unvested restricted stock awards:
Number of Shares | Weighted- Average Grant Date Fair Value | ||||||||||
| (In thousands) | |||||||||||
| Unvested restricted shares outstanding at December 31, 2018 | 365 | $ | 16.07 | ||||||||
| Granted | 93 | $ | 8.06 | ||||||||
| Vested | (210) | $ | 16.29 | ||||||||
| Forfeited / Canceled | (15) | $ | 16.25 | ||||||||
| Unvested restricted shares outstanding at December 31, 2019 | 233 | $ | 12.66 | ||||||||
| Granted | 105 | $ | 2.15 | ||||||||
| Vested | (174) | $ | 11.53 | ||||||||
| Forfeited / Canceled | (50) | $ | 15.97 | ||||||||
| Unvested restricted shares outstanding at December 31, 2020 | 114 | $ | 3.26 | ||||||||
| Granted | 56 | $ | 5.26 | ||||||||
| Vested (1) | (111) | $ | 2.99 | ||||||||
| Forfeited / Canceled | (2) | $ | 16.25 | ||||||||
| Unvested restricted shares outstanding at December 31, 2021 | 57 | $ | 5.26 | ||||||||
____________________
(1) The aggregate intrinsic value of restricted stock that vested during 2021 was approximately $0.6 million based on the stock price at the time of vesting.
Restricted Stock Units. The Company’s restricted stock units awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Outstanding restricted stock units at December 31, 2021 will generally vest over a three-year period with a remaining weighted average contractual period of 2.19 years and have $1.4 million associated unrecognized compensation cost at year in December 31, 2021.
The following table presents a summary of the Company’s unvested restricted stock units:
| Number of Units | Weighted- Average Grant Date Fair Value | |||||||||||||
| (In thousands) | ||||||||||||||
| Unvested restricted stock units outstanding at December 31, 2020 | 1,410 | $ | 1.10 | |||||||||||
| Granted | 178 | $ | 7.58 | |||||||||||
| Vested (1) | (477) | $ | 1.14 | |||||||||||
| Forfeited / Canceled | (705) | $ | 0.94 | |||||||||||
| Unvested restricted stock units outstanding at December 31, 2021 | 406 | $ | 4.18 | |||||||||||
____________________
(1) The aggregate intrinsic value of restricted stock units that vested during 2021 was approximately $2.4 million based on the stock price at the time of vesting.
Performance Share Units. The Company’s performance share units awards are equity-classified awards and are valued based upon the market value of the Company’s common stock on the date of grant. Outstanding performance share units at December 31, 2021 will generally vest over a three year period with a remaining weighted average contractual period of 0.15 years and an immaterial amount of unrecognized compensation cost at year in December 31, 2021.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
The following table presents a summary of the Company's performance share units:
| Number of Units | Weighted- Average Grant Date Fair Value | |||||||||||||
| (In thousands) | ||||||||||||||
| Unvested performance share units outstanding at December 31, 2018 | 111 | $ | 20.41 | |||||||||||
| Granted | — | |||||||||||||
| Vested | (19) | $ | 15.11 | |||||||||||
| Forfeited / Canceled | — | |||||||||||||
| Unvested performance share units outstanding at December 31, 2019 | 92 | $ | 20.41 | |||||||||||
| Granted | 205 | $ | 1.66 | |||||||||||
| Vested | (92) | $ | 20.41 | |||||||||||
| Forfeited / Canceled | — | |||||||||||||
| Unvested performance share units outstanding at December 31, 2020 | 205 | $ | 1.66 | |||||||||||
| Granted | 39 | $ | 5.01 | |||||||||||
| Vested (1) | (197) | $ | 1.70 | |||||||||||
| Forfeited / Canceled | (13) | $ | 2.38 | |||||||||||
| Unvested performance share units outstanding at December 31, 2021 | 34 | $ | 5.01 | |||||||||||
____________________
(1) The aggregate intrinsic value of performance share units that vested during 2021 was approximately $0.8 million.
Stock Options
The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on the exercise of stock options, post-vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant. Generally, stock options granted to employees and
directors vest ratably over three years from the grant date and expire seven years from the date of grant.
| Assumptions | For the Year Ended December 31, 2021 | |||||||
| Risk-free interest rate | 0.79 | % | ||||||
| Expected dividend yield | — | % | ||||||
| Expected volatility | 78.2 | % | ||||||
| Expected term | 5 years | |||||||
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The following table presents a summary of the Company's stock option activity for the year ended December 31, 2021 and 2020:
| Number of Shares | Weighted Average Exercise Price per Share | Weighted Average Remaining Contractual Term(years) | Aggregate Intrinsic Value (in millions) | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
| Outstanding at December 31, 2019 | — | $ | — | — | $ | — | ||||||||||||||||||||
| Granted | 245 | — | — | — | ||||||||||||||||||||||
| Forfeited / Canceled | (154) | — | — | — | ||||||||||||||||||||||
| Outstanding at December 31, 2020 | 91 | $ | — | 2.68 | $ | 0.24 | ||||||||||||||||||||
| Exercisable at December 31, 2020 | — | $ | — | — | $ | — | ||||||||||||||||||||
| Outstanding at December 31, 2020 | 91 | $ | — | 2.68 | $ | 0.24 | ||||||||||||||||||||
| Granted | 250 | — | — | — | ||||||||||||||||||||||
| Exercised | (9) | $ | 6.43 | — | — | |||||||||||||||||||||
| Expired | (1) | — | — | — | ||||||||||||||||||||||
| Forfeited / Canceled | (7) | — | — | — | ||||||||||||||||||||||
| Outstanding at December 31, 2021 (1) | 324 | $ | — | 7.80 | $ | 0.80 | ||||||||||||||||||||
| Exercisable at December 31, 2021 | 24 | $ | — | 1.59 | $ | 0.19 | ||||||||||||||||||||
____________________
(1) All outstanding stock options as of December 31, 2021 are expected to vest.
In August 2021 and February 2020, the Company granted nonqualified stock options. As of December 31, 2021, the total unrecognized compensation expense was $1.4 million and will be recognized over a weighted average period of 4.60 years.
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
The following tables summarize the Company's share and incentive-based compensation for the years ended December 31, 2021, 2020 and 2019 (in thousands):
| Recurring Compensation Expense (1) | Executive Terminations (2) | Reduction in Force (2) | Accelerated Vesting (3) | Total | ||||||||||||||||||||||||||||
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||||||||
| Equity-classified awards: | ||||||||||||||||||||||||||||||||
| Restricted stock awards and units | $ | 773 | $ | — | $ | 11 | $ | — | $ | 784 | ||||||||||||||||||||||
| Performance share units | 476 | — | 6 | — | 482 | |||||||||||||||||||||||||||
| Stock options | 128 | — | — | — | 128 | |||||||||||||||||||||||||||
| Total share-based compensation expense | 1,377 | — | 17 | — | 1,394 | |||||||||||||||||||||||||||
| Less: Capitalized compensation expense | — | — | — | — | — | |||||||||||||||||||||||||||
| Share and incentive-based compensation expense, net | $ | 1,377 | $ | — | $ | 17 | $ | — | $ | 1,394 | ||||||||||||||||||||||
| Year Ended December 31, 2020 | ||||||||||||||||||||||||||||||||
| Equity-classified awards: | ||||||||||||||||||||||||||||||||
| Restricted stock awards | $ | 974 | $ | 508 | $ | 40 | $ | — | $ | 1,522 | ||||||||||||||||||||||
| Performance share units | 211 | 1,276 | — | — | 1,487 | |||||||||||||||||||||||||||
| Stock options | 22 | — | — | — | 22 | |||||||||||||||||||||||||||
| Total share-based compensation expense | 1,207 | 1,784 | 40 | — | 3,031 | |||||||||||||||||||||||||||
| Less: Capitalized compensation expense | (19) | — | — | — | (19) | |||||||||||||||||||||||||||
| Share and incentive-based compensation expense, net | $ | 1,188 | $ | 1,784 | $ | 40 | $ | — | $ | 3,012 | ||||||||||||||||||||||
| Year Ended December 31, 2019 | ||||||||||||||||||||||||||||||||
| Equity-classified awards: | ||||||||||||||||||||||||||||||||
| Restricted stock awards | $ | 2,526 | $ | 197 | $ | 500 | $ | — | $ | 3,223 | ||||||||||||||||||||||
| Performance share units | 282 | 281 | — | — | 563 | |||||||||||||||||||||||||||
| Stock options | 661 | 12 | — | — | 673 | |||||||||||||||||||||||||||
| Total share-based compensation expense | 3,469 | 490 | 500 | — | 4,459 | |||||||||||||||||||||||||||
| Less: Capitalized compensation expense | (204) | — | — | — | (204) | |||||||||||||||||||||||||||
| Share and incentive-based compensation expense, net | $ | 3,265 | $ | 490 | $ | 500 | $ | — | $ | 4,255 | ||||||||||||||||||||||
____________________
(1)Recorded in general and administrative expense in the accompanying consolidated statements of operations.
(2)Recorded in employee termination benefits in the accompanying consolidated statements of operations.
(3)Recorded in accelerated vesting of employment compensation in the accompanying consolidated statements of operations.
18. Incentive and Deferred Compensation Plans
Annual Incentive Plan. The Annual Incentive Plan ("AIP") incorporates quantitative performance measures, strategic qualitative goals and competitive target award levels for management and employees for the 2021 and 2020 performance years. Incentive bonus awards for 2021 will be provided based on performance measures related to health, safety and environment, production, operating expenses, among other metrics and will be paid in 2022 at the discretion of the Board of Directors. As of December 31, 2021 and 2020, the Company accrued approximately $2.1 million and $2.6 million, respectively for AIP. AIP Payments totaling $2.1 million were paid in 2021 for the 2020 performance year and $1.1 million were paid in 2020 for the 2019 performance year.
401(k) Plan. The Company maintains a 401(k) retirement plan for its employees. Under this plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by the IRS. For the years ended December 31, 2021, 2021, 2020 and 2019, the Company made matching contributions to the plan equal to 100% on the first 10% of employee
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| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
deferred wages, excluding incentive compensation, totaling $0.8 million, $1.1 million and $2.2 million, respectively. The decrease in contributions is due primarily to reductions in force that occurred in each of those years. Participants in the plan are immediately 100% vested in the discretionary employee contributions and related earnings on those contributions. The Company's matching contributions and related earnings vest based on years of service, with full vesting occurring on the fourth anniversary of employment.
19. Employee Termination Benefits
The following table presents a summary of employee termination benefits for the years ended December 31, 2021, 2020 and 2019 (in thousands):
| Cash | Share-Based Compensation (4) | Number of Shares | Total Employee Termination Benefits | |||||||||||||||||||||||
| Year Ended December 31, 2021 | ||||||||||||||||||||||||||
| Executive Employee Termination Benefits | $ | — | $ | — | — | $ | — | |||||||||||||||||||
| Other Employee Termination Benefits | 32 | 17 | — | 49 | ||||||||||||||||||||||
| $ | 32 | $ | 17 | — | $ | 49 | ||||||||||||||||||||
| Year Ended December 31, 2020 | ||||||||||||||||||||||||||
| Executive Employee Termination Benefits (1) | $ | 1,009 | $ | 1,784 | 159 | $ | 2,793 | |||||||||||||||||||
| Other Employee Termination Benefits | 5,600 | 40 | 4 | 5,640 | ||||||||||||||||||||||
| $ | 6,609 | $ | 1,824 | 163 | $ | 8,433 | ||||||||||||||||||||
| Year Ended December 31, 2019 | ||||||||||||||||||||||||||
| Executive Employee Termination Benefits (2) | $ | 1,194 | $ | 490 | 37 | $ | 1,684 | |||||||||||||||||||
| Other Employee Termination Benefits (3) | 2,608 | 500 | 44 | 3,108 | ||||||||||||||||||||||
| $ | 3,802 | $ | 990 | 81 | $ | 4,792 | ||||||||||||||||||||
____________________
(1) On July 1, 2020, the Company's then current Chief Financial Officer, Michael A. Johnson and Chief Operating Officer, John Suter, separated employment from the Company. As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with these separations during 2020.
(2) On December 12, 2019, the Company's then current CEO, Paul McKinney, separated employment from the Company, and on June 14, 2019, the Company’s then current Executive Vice President, General Counsel and Corporate Secretary, Philip Warman, separated employment from the Company. As a result, the Company paid cash severance costs and incurred share-based compensation costs associated with these separations during 2019.
(3) As a result of a reduction in workforce in the second quarter of 2019, certain employees received termination benefits including cash severance and accelerated share-based compensation upon separation of service from the Company.
(4) Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards due to the sale of the North Park assets for the year end December 31, 2021 and performance share units upon the departure of certain executives and the reductions in workforce in 2020 and 2019 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination was recorded as employee termination benefits. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. NaN share of the Company’s common stock was issued per performance share unit.
As of December 31, 2020 there were no longer any legacy employment contracts.
See Note 17 for additional discussion of the Company’s share-based compensation awards.
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20. Earnings (Loss) per Share
The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share:
| Net Income (Loss) | Weighted Average Shares | Earnings (Loss) Per Share | ||||||||
| (In thousands, except per share amounts) | ||||||||||
| Year Ended December 31, 2017 (Successor) | ||||||||||
| Basic earnings per share | $ | 47,062 | 32,442 | $ | 1.45 | |||||
| Effect of dilutive securities | ||||||||||
| Restricted stock awards | — | 221 | ||||||||
| Performance share units(1) | — | — | ||||||||
| Warrants(1) | — | — | ||||||||
| Diluted earnings per share | $ | 47,062 | 32,663 | $ | 1.44 | |||||
| Period from October 2, 2016 to December 31, 2016 (Successor) | ||||||||||
| Basic loss per share | $ | (333,982 | ) | 18,967 | $ | (17.61 | ) | |||
| Effect of dilutive securities | ||||||||||
| Restricted stock(2) | — | — | ||||||||
| Warrants(2) | — | — | ||||||||
| Convertible Notes(3) | — | — | ||||||||
| Diluted loss per share | $ | (333,982 | ) | 18,967 | $ | (17.61 | ) | |||
| Period from January 1, 2016 to October 1, 2016 (Predecessor) | ||||||||||
| Basic earnings per share | $ | 1,424,476 | 708,928 | $ | 2.01 | |||||
| Effect of dilutive securities | ||||||||||
| Restricted stock and units(4) | — | — | ||||||||
| Diluted earnings per share | $ | 1,424,476 | 708,928 | $ | 2.01 | |||||
| Year Ended December 31, 2015 (Predecessor) | ||||||||||
| Basic loss per share | $ | (3,735,495 | ) | 521,936 | $ | (7.16 | ) | |||
| Effect of dilutive securities | ||||||||||
| Restricted stock and units(4) | — | — | ||||||||
| Convertible preferred stock (5) | — | — | ||||||||
| Convertible senior unsecured notes(6) | — | — | ||||||||
| Diluted loss per share | $ | (3,735,495 | ) | 521,936 | $ | (7.16 | ) | |||
| Net Earnings (Loss) | Weighted Average Shares | Earnings (Loss) Per Share | |||||||||||||||
| (In thousands, except per share amounts) | |||||||||||||||||
| Year Ended December 31, 2021 | |||||||||||||||||
| Basic earnings per share | $ | 116,738 | 36,393 | $ | 3.21 | ||||||||||||
| Effect of dilutive securities | |||||||||||||||||
| Restricted stock awards (1) | — | 58 | |||||||||||||||
| Restricted share units (1) | — | 689 | |||||||||||||||
| Performance share units (1) | — | 83 | |||||||||||||||
| Stock Options (1) | — | 48 | |||||||||||||||
| Warrants | — | — | |||||||||||||||
| Diluted earnings per share | $ | 116,738 | 37,271 | $ | 3.13 | ||||||||||||
| Year Ended December 31, 2020 | |||||||||||||||||
| Basic loss per share | $ | (277,353) | 35,689 | $ | (7.77) | ||||||||||||
| Effect of dilutive securities | |||||||||||||||||
| Restricted stock awards (2) | — | — | |||||||||||||||
| Restricted share units (2) | — | — | |||||||||||||||
| Performance share units (2) | — | — | |||||||||||||||
| Stock Options (2) | — | — | |||||||||||||||
| Warrants (2) | — | — | |||||||||||||||
| Diluted loss per share | $ | (277,353) | 35,689 | $ | (7.77) | ||||||||||||
| Year Ended December 31, 2019 | |||||||||||||||||
| Basic loss per share | $ | (449,305) | 35,427 | $ | (12.68) | ||||||||||||
| Effect of dilutive securities | |||||||||||||||||
| Restricted stock awards (2) | — | — | |||||||||||||||
| Restricted share units (2) | — | — | |||||||||||||||
| Performance share units (2) | — | — | |||||||||||||||
| Stock Options (2) | — | — | |||||||||||||||
| Warrants (2) | — | — | |||||||||||||||
| Diluted loss per share | $ | (449,305) | 35,427 | $ | (12.68) | ||||||||||||
____________________
(1)The incremental shares of potentially dilutive restricted stock awards, restricted stock units, performance share units |
See Note 1617 for discussion of the Predecessor Company’s convertible perpetual preferred stock. The remaining outstanding Convertible Notes were converted into shares of Common Stock as when the Company refinanced its credit facility on February 10, 2017.
The supplemental information below includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.
91
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
Capitalized Costs Related to Oil and Natural Gas Producing Activities
The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):
| December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Oil and natural gas properties | |||||||||||||||||
| Proved | $ | 1,454,016 | $ | 1,463,950 | $ | 1,484,359 | |||||||||||
| Unproved | 12,255 | 17,964 | 24,603 | ||||||||||||||
| Total oil and natural gas properties | 1,466,271 | 1,481,914 | 1,508,962 | ||||||||||||||
| Less accumulated depreciation, depletion and impairment | (1,373,217) | (1,375,692) | (1,129,622) | ||||||||||||||
| Net oil and natural gas properties capitalized costs | $ | 93,054 | $ | 106,222 | $ | 379,340 | |||||||||||
| Successor | Predecessor | |||||||||||
| December 31, | December 31, | December 31, | ||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Oil and natural gas properties | ||||||||||||
| Proved | $ | 1,056,806 | $ | 840,201 | $ | 12,529,681 | ||||||
| Unproved | 100,884 | 74,937 | 363,149 | |||||||||
| Total oil and natural gas properties | 1,157,690 | 915,138 | 12,892,830 | |||||||||
| Less accumulated depreciation, depletion and impairment | (460,431 | ) | (353,030 | ) | (11,149,888 | ) | ||||||
| Net oil and natural gas properties capitalized costs | $ | 697,259 | $ | 562,108 | $ | 1,742,942 | ||||||
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development
Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Acquisitions of properties | |||||||||||||||||
| Proved | $ | 3,545 | $ | 3,701 | $ | (210) | |||||||||||
| Unproved | — | — | 2,653 | ||||||||||||||
| Exploration (1) | 905 | 1,005 | 2,900 | ||||||||||||||
| Development | 10,045 | 3,563 | 156,210 | ||||||||||||||
| Total cost incurred | $ | 14,495 | $ | 8,269 | $ | 161,553 | |||||||||||
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Acquisitions of properties | ||||||||||||||||
| Proved | $ | 7,092 | $ | 5,142 | $ | 3,897 | $ | 35,376 | ||||||||
| Unproved | 91,139 | 5,491 | 1,899 | 210,065 | ||||||||||||
| Exploration(1) | 8,850 | — | 1,234 | 29,297 | ||||||||||||
| Development | 187,264 | 27,429 | 149,924 | 571,562 | ||||||||||||
| Total cost incurred | $ | 294,345 | $ | 38,062 | $ | 156,954 | $ | 846,300 | ||||||||
Results of Operations for Oil and Natural Gas Producing Activities
The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the contribution to net earnings ofimpact the Company’s operations.operations have on actual net earnings.
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Revenues | $ | 168,882 | $ | 114,450 | $ | 266,104 | |||||||||||
| Expenses | |||||||||||||||||
| Production costs | 46,309 | 53,474 | 110,711 | ||||||||||||||
| Depreciation and depletion | 9,372 | 50,349 | 146,874 | ||||||||||||||
| Impairment | — | 218,399 | 409,574 | ||||||||||||||
| Total expenses | 55,681 | 322,222 | 667,159 | ||||||||||||||
| Income (loss) before income taxes | 113,201 | (207,772) | (401,055) | ||||||||||||||
| Income tax expense (benefit) (1) | 26,734 | (51,750) | (105,477) | ||||||||||||||
| Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) | $ | 86,467 | $ | (156,022) | $ | (295,578) | |||||||||||
____________________
(1) Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to (loss) income before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Revenues | $ | 356,210 | $ | 98,307 | $ | 279,971 | $ | 707,434 | ||||||||
| Expenses | ||||||||||||||||
| Production costs | 116,372 | 27,640 | 135,715 | 324,141 | ||||||||||||
| Depreciation and depletion | 118,035 | 36,061 | 90,978 | 324,390 | ||||||||||||
| Impairment | — | 319,087 | 657,392 | 4,473,787 | ||||||||||||
| Total expenses | 234,407 | 382,788 | 884,085 | 5,122,318 | ||||||||||||
| Income (loss) before income taxes | 121,803 | (284,481 | ) | (604,114 | ) | (4,414,884 | ) | |||||||||
| Income tax expense (benefit)(1) | 47,722 | (112,427 | ) | (229,986 | ) | (1,680,746 | ) | |||||||||
| Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs) | $ | 74,081 | $ | (172,054 | ) | $ | (374,128 | ) | $ | (2,734,138 | ) | |||||
92
Notes to | ||||||||
Oil, Natural Gas and NGL Reserve Quantities
Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. 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 mandated economic assumptions; and
•the judgment of the personnel preparing the estimates.
Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.
Cawley, Gillespie & Associates, Inc. (“CG&A”), Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majorityfor over 96% of the Company’s net interest in oil and natural gas properties as of the end of 2017, 20162021 and 2015. CG&A,Cawley, Gillespie & Associates and Ryder Scott together prepared over 90% as of the end of 2020 and Netherland Sewell2019. Cawley, Gillespie & Associates and Ryder Scott are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates.
The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existingrecent, past or historical economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.
93
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | ||||||||
shut-ins, sales and resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that have been developed with three or more horizontal wells per section as inter-well pressure communication has had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in the Company’s Mississippian wells producing with artificial lift have resulted in increased production decline rates that are now becoming more predictable on a large group of base wells as this population of wells has been producing for more than two years. Of the total performance revisions, approximately 85% were to gas and associated NGL reserves, with the revisions to gas mostly from changes made to late-life decline rates, and 15% were to oil reserves. Other decreases of reserves excluding production included the sale of WTO reserves of 24.6 MMBoe and 19.1 MMBoe of adjustment from change in accounting for Trusts.other revisions. These decreasesreductions were partially offset by approximately 7.8an 8.6 MMBoe increase associated with reduction in expenses and other commercial improvements, and purchases of 1.1 MMBoe of extensions dueproved reserves.
2019 Activity. Proved reserves decreased from 160.2 MMBoe at December 31, 2018 to successful drilling.
The summary below presents changes in the Company’s estimated reserves. NPB is included in 2021, 2020 and 2019.
| Oil | NGL | Natural Gas | Total | ||||||||||||||||||||
| (MBbls) | (MBbls) | (MMcf) (1) | MBoe | ||||||||||||||||||||
| Proved developed and undeveloped reserves | |||||||||||||||||||||||
| As of December 31, 2018 | 64,019 | 28,175 | 407,891 | 160,176 | |||||||||||||||||||
| Revisions of previous estimates | (25,530) | (9,277) | (142,239) | (58,514) | |||||||||||||||||||
| Acquisitions of new reserves | — | — | — | — | |||||||||||||||||||
| Extensions and discoveries | 635 | 94 | 2,127 | 1,084 | |||||||||||||||||||
| Sales of reserves in place | (297) | (223) | (2,308) | (905) | |||||||||||||||||||
| Production | (3,519) | (2,910) | (33,164) | (11,956) | |||||||||||||||||||
| As of December 31, 2019 | 35,308 | 15,859 | 232,307 | 89,885 | |||||||||||||||||||
| Revisions of previous estimates | (24,650) | (2,246) | (107,426) | (44,800) | |||||||||||||||||||
| Acquisitions of new reserves | 74 | 437 | 3,391 | 1,076 | |||||||||||||||||||
| Extensions and discoveries | — | — | — | — | |||||||||||||||||||
| Sales of reserves in place | (163) | (111) | (1,827) | (579) | |||||||||||||||||||
| Production | (2,084) | (2,694) | (23,552) | (8,703) | |||||||||||||||||||
| As of December 31, 2020 | 8,485 | 11,245 | 102,893 | 36,879 | |||||||||||||||||||
| Revisions of previous estimates (2) | 3,627 | 14,924 | 148,736 | 43,340 | |||||||||||||||||||
| Acquisitions of new reserves | 135 | 438 | 5,235 | 1,446 | |||||||||||||||||||
| Extensions and discoveries | — | — | — | — | |||||||||||||||||||
| Sales of reserves in place | (3440) | (28) | (716) | (3,587) | |||||||||||||||||||
| Production | (957) | (2,266) | (21,417) | (6,793) | |||||||||||||||||||
| As of December 31, 2021 | 7,850 | 24,313 | 234,731 | 71,285 | |||||||||||||||||||
| Proved developed reserves | |||||||||||||||||||||||
| As of December 31, 2019 | 14,078 | 14,532 | 200,853 | 62,086 | |||||||||||||||||||
| As of December 31, 2020 | 8,485 | 11,245 | 102,893 | 36,879 | |||||||||||||||||||
| As of December 31, 2021 | 7,850 | 24,313 | 234,731 | 71,285 | |||||||||||||||||||
| Proved undeveloped reserves | |||||||||||||||||||||||
| As of December 31, 2019 | 21,230 | 1,327 | 31,454 | 27,799 | |||||||||||||||||||
| As of December 31, 2020 | — | — | — | — | |||||||||||||||||||
| As of December 31, 2021 | — | — | — | — | |||||||||||||||||||
_________________
(1) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(2) Revisions include changes due to previous quantity estimates, pricing, and productions costs.
94
| Oil | NGL | Natural Gas | Total | ||||||||
| (MBbls) | (MBbls) | (MMcf)(1) | MBoe | ||||||||
| Proved developed and undeveloped reserves | |||||||||||
| As of December 31, 2014(2) - Predecessor | 126,031 | 91,786 | 1,788,233 | 515,856 | |||||||
| Revisions of previous estimates | (70,708 | ) | (37,384 | ) | (759,106 | ) | (234,610 | ) | |||
| Acquisitions of new reserves | 22,447 | 2,460 | 15,952 | 27,566 | |||||||
| Extensions and discoveries | 9,741 | 9,257 | 160,865 | 45,809 | |||||||
| Production | (9,600 | ) | (5,044 | ) | (92,104 | ) | (29,995 | ) | |||
| As of December 31, 2015(2) - Predecessor | 77,911 | 61,075 | 1,113,840 | 324,626 | |||||||
| Adoption of ASU 2015-02 | (6,971 | ) | (3,695 | ) | (50,508 | ) | (19,084 | ) | |||
| Revisions of previous estimates | (39,973 | ) | (21,475 | ) | (415,568 | ) | (130,709 | ) | |||
| Extensions and discoveries | 987 | 472 | 7,955 | 2,785 | |||||||
| Sales of reserves in place | (387 | ) | — | (145,267 | ) | (24,598 | ) | ||||
| Production | (4,315 | ) | (3,358 | ) | (44,124 | ) | (15,027 | ) | |||
| As of October 1, 2016 - Predecessor | 27,252 | 33,019 | 466,328 | 137,992 | |||||||
| Revisions of previous estimates | 23,978 | 1,139 | 915 | 25,270 | |||||||
| Extensions and discoveries | 2,868 | 448 | 10,309 | 5,034 | |||||||
| Production | (1,214 | ) | (999 | ) | (12,770 | ) | (4,341 | ) | |||
| As of December 31, 2016 - Successor | 52,884 | 33,607 | 464,782 | 163,955 | |||||||
| Revisions of previous estimates | 804 | 2,628 | 44,679 | 10,879 | |||||||
| Acquisitions of new reserves | 18 | 70 | 683 | 202 | |||||||
| Extensions and discoveries | 12,446 | 1,914 | 30,080 | 19,373 | |||||||
| Sales of reserves in place | (204 | ) | (529 | ) | (7,055 | ) | (1,909 | ) | |||
| Production | (4,157 | ) | (3,376 | ) | (44,237 | ) | (14,906 | ) | |||
| As of December 31, 2017 - Successor | 61,791 | 34,314 | 488,932 | 177,594 | |||||||
| Proved developed reserves | |||||||||||
| As of December 31, 2014 - Predecessor | 79,022 | 56,823 | 1,203,447 | 336,420 | |||||||
| As of December 31, 2015 - Predecessor | 48,639 | 51,089 | 964,617 | 260,498 | |||||||
| As of October 1, 2016 - Predecessor | 24,541 | 30,238 | 428,050 | 126,121 | |||||||
| As of December 31, 2016 - Successor | 25,911 | 29,290 | 393,028 | 120,706 | |||||||
| As of December 31, 2017 - Successor | 25,845 | 29,922 | 407,988 | 123,765 | |||||||
| Proved undeveloped reserves | |||||||||||
| As of December 31, 2014 - Predecessor | 47,009 | 34,963 | 584,786 | 179,436 | |||||||
| As of December 31, 2015 - Predecessor | 29,272 | 9,986 | 149,223 | 64,129 | |||||||
| As of October 1, 2016 - Predecessor | 2,711 | 2,781 | 38,278 | 11,872 | |||||||
| As of December 31, 2016 - Successor | 26,973 | 4,317 | 71,754 | 43,249 | |||||||
| As of December 31, 2017 - Successor | 35,946 | 4,392 | 80,944 | 53,829 | |||||||
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | |||||
| Predecessor | |||||
| December 31, | |||||
| 2015 | 2014 | ||||
| Oil (MBbl) | 7,004 | 11,027 | |||
| NGL (MBbl) | 3,694 | 4,761 | |||
| Natural gas (MMcf) | 50,508 | 70,833 | |||
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas, (“("ASC Topic 932”932"). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:
•the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;
| Successor | Predecessor | |||||||||||
| December 31, | December 31, | December 31, | ||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Oil (per barrel) | $ | 48.47 | $ | 38.59 | $ | 45.29 | ||||||
| NGL (per barrel) | $ | 20.28 | $ | 10.99 | $ | 12.68 | ||||||
| Natural gas (per Mcf) | $ | 1.90 | $ | 1.56 | $ | 1.87 | ||||||
•pricing is applied based upon SEC prices at December 31, 2021, 2020 and 2019, adjusted for fixed or determinable contracts that are in existence at year-end.
The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:
| At December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Oil (per Bbl) | $ | 64.95 | $ | 36.54 | $ | 50.63 | |||||||||||
| NGL (per Bbl) | $ | 19.26 | $ | 6.40 | $ | 12.45 | |||||||||||
| Natural gas (per Mcf) | $ | 2.56 | $ | 0.87 | $ | 1.16 | |||||||||||
•future development and production costs are determined based upon actualon trailing 12 month average cost at year-end;
•the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and
•a discount factor of 10% per year is applied annually to the future net cash flows.
The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).
| December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Future cash inflows from production | $ | 1,579,734 | $ | 471,038 | $ | 2,254,530 | |||||||||||
| Future production costs | (735,904) | (270,512) | (1,028,695) | ||||||||||||||
| Future development costs (1) | (66,732) | (81,687) | (536,081) | ||||||||||||||
| Future income tax expenses (2) | — | — | — | ||||||||||||||
| Undiscounted future net cash flows | 777,098 | 118,839 | 689,754 | ||||||||||||||
| 10% annual discount | (344,184) | (13,853) | (325,464) | ||||||||||||||
| Standardized measure of discounted future net cash flows (3) | $ | 432,914 | $ | 104,986 | $ | 364,290 | |||||||||||
____________________
(1) Includes abandonment costs.
(2) The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards.
(3) NPB is included in 2020 and 2019.
| Successor | Predecessor | |||||||||||
| December 31, | December 31, | December 31, | ||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Future cash inflows from production | $ | 4,621,615 | $ | 3,136,762 | $ | 6,387,944 | ||||||
| Future production costs | (1,837,852 | ) | (1,454,798 | ) | (2,731,542 | ) | ||||||
| Future development costs(1) | (966,203 | ) | (665,516 | ) | (838,945 | ) | ||||||
| Future income tax expenses | (107 | ) | (142 | ) | (901 | ) | ||||||
| Undiscounted future net cash flows | 1,817,453 | 1,016,306 | 2,816,556 | |||||||||
| 10% annual discount | (1,068,159 | ) | (577,942 | ) | (1,501,994 | ) | ||||||
| Standardized measure of discounted future net cash flows(2) | $ | 749,294 | $ | 438,364 | $ | 1,314,562 | ||||||
95
| SandRidge Energy, Inc. and Subsidiaries Notes to Consolidated Financial Statements | |||
The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Beginning present value | $ | 104,986 | $ | 364,290 | $ | 1,045,603 | |||||||||||
| Changes during the year | |||||||||||||||||
| Revenues less production | (122,964) | (61,407) | (155,772) | ||||||||||||||
| Net changes in prices, production and other costs | 380,026 | (135,652) | (491,035) | ||||||||||||||
| Development costs incurred | 83 | — | 90,591 | ||||||||||||||
| Net changes in future development costs (1) | 446 | (2,167) | 450,162 | ||||||||||||||
| Extensions and discoveries | — | — | 11,921 | ||||||||||||||
| Revisions of previous quantity estimates (1) | 112,926 | (99,533) | (478,238) | ||||||||||||||
| Accretion of discount | 6,016 | 36,429 | 101,778 | ||||||||||||||
| Purchases of reserves in-place | 15,541 | 4,744 | — | ||||||||||||||
| Sales of reserves in-place | (29,792) | (1,067) | (3,331) | ||||||||||||||
| Timing differences and other (2) | (34,354) | (651) | (207,389) | ||||||||||||||
| Net change for the year | 327,928 | (259,304) | (681,313) | ||||||||||||||
| Ending present value (3) (4) | $ | 432,914 | $ | 104,986 | $ | 364,290 | |||||||||||
____________________
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2017 | Period from October 2, 2016 through December 31, 2016 | Period from January 1, 2016 through October 1, 2016 | Year Ended December 31, 2015 | |||||||||||||
| Beginning present value | $ | 438,364 | $ | 392,604 | $ | 1,314,562 | $ | 4,087,752 | ||||||||
| Changes during the year | ||||||||||||||||
| Adoption of ASU 2015-02 | — | — | (224,965 | ) | — | |||||||||||
| Revenues less production | (239,838 | ) | (70,668 | ) | (144,256 | ) | (383,293 | ) | ||||||||
| Net changes in prices, production and other costs | 347,458 | 35,684 | (394,173 | ) | (3,813,465 | ) | ||||||||||
| Development costs incurred | 35,517 | 7,941 | 69,080 | 217,596 | ||||||||||||
| Net changes in future development costs | (64,484 | ) | (291,232 | ) | 436,041 | 273,437 | ||||||||||
| Extensions and discoveries | 112,556 | 14,986 | 12,449 | 230,055 | ||||||||||||
| Revisions of previous quantity estimates | 26,697 | 308,374 | (728,254 | ) | (1,354,778 | ) | ||||||||||
| Accretion of discount | 37,226 | 9,375 | 91,337 | 512,483 | ||||||||||||
| Net change in income taxes | 23 | — | 402 | 1,426,333 | ||||||||||||
| Purchases of reserves in-place | 454 | — | — | 18,429 | ||||||||||||
| Sales of reserves in-place | (2,977 | ) | — | (13,314 | ) | — | ||||||||||
| Timing differences and other(1) | 58,298 | 31,300 | (26,305 | ) | 100,013 | |||||||||||
| Net change for the year | 310,930 | 45,760 | (921,958 | ) | (2,773,190 | ) | ||||||||||
| Ending present value(2) | $ | 749,294 | $ | 438,364 | $ | 392,604 | $ | 1,314,562 | ||||||||
(2) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.
(3) Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices.
(4) NPB is included in 2020 and 2019.
22. Subsequent Events
As of the filing date of this report, the Company does not have any open derivative contracts.
96
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures.
Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(b) and 15d-15(b) as of the end of the period covered by this annual report. Based on that evaluation, the Company’s Chief Executive Officer and its Chief Financial Officer concluded that its disclosure controls and procedures were effective as of December 31, 2021 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
The information required to be filed pursuant to this item is set forth under the captions “Management’s Report on Internal Control over Financial Reporting” in Item 8 of this report.
Changes in Internal Control over Financial Reporting
There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Item 9B. Other Information
Not applicable.
97
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 30, 2022: “Director Biographical Information,” “Executive Officers,” “Compliance with Section 16(a) of the Exchange Act” and “Corporate Governance Matters.”
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 30, 2022: “Director Compensation,” “Outstanding Equity Awards” and “Executive Officers and Compensation.”
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 30, 2022: “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management.”
Item 13. Certain Relationships and Related Transactions and Director Independence
The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 30, 2022: “Related Party Transactions” and “Corporate Governance Matters.”
Item 14. Principal Accounting Fees and Services
The information required by this item is incorporated herein by reference to the section captioned “Ratification of Selection of Independent Registered Public Accounting Firm” in the Company’s definitive proxy statement, which will be filed no later than April 30, 2022.
98
PART IV
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as a part of this report:
1.Consolidated Financial Statements
2.Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.
3.Exhibits
EXHIBIT INDEX
| Incorporated by Reference | ||||||||||||||||||||
Exhibit No. | Exhibit Description | Form | SEC File No. | Exhibit | Filing Date | Filed Herewith | ||||||||||||||
| 2.1 | 8-A | 001-33784 | 2.1 | 10/4/2016 | ||||||||||||||||
| 3.1 | 8-A | 001-33784 | 3.1 | 10/4/2016 | ||||||||||||||||
| 3.2 | 8-A | 001-33784 | 3.2 | 10/4/2016 | ||||||||||||||||
| 3.3 | 8-K | 001-33784 | 3.1 | 11/27/2017 | ||||||||||||||||
| 3.4 | 8-A | 001-33784 | 3.1 | 7/2/2020 | ||||||||||||||||
| 4.1 | 8-K | 001-33784 | 4.1 | 10/7/2016 | ||||||||||||||||
| 4.2 | 8-K | 001-33784 | 10.6 | 10/7/2016 | ||||||||||||||||
| 4.3 | 8-A | 001-33784 | 10.1 | 10/4/2016 | ||||||||||||||||
| 4.4 | 8-K | 001-33784 | 4.1 | 11/27/2017 | ||||||||||||||||
| 4.5 | 8-K | 001-33784 | 4.1 | 1/23/2018 | ||||||||||||||||
| 4.6 | 10-K | 001-33784 | 4.6 | 2/27/2020 | * | |||||||||||||||
| 10.1† | 8-K | 001-33784 | 10.8 | 10/7/2016 | ||||||||||||||||
| 10.1.1† | 10-K | 001-33784 | 10.1.4 | 3/3/2017 | ||||||||||||||||
99
| Incorporated by Reference | ||||||||||||||||||||
Exhibit No. | Exhibit Description | Form | SEC File No. | Exhibit | Filing Date | Filed Herewith | ||||||||||||||
| 10.1.1.1† | 10-Q | 001-33784 | 10.1.4.1 | 11/3/2017 | ||||||||||||||||
| 10.1.2† | 10-K | 001-33784 | 10.1.5 | 3/3/2017 | ||||||||||||||||
| 10.1.3† | 10-Q | 001-33784 | 10.1.6 | 8/7/2017 | ||||||||||||||||
| 10.1.3.1† | 10-Q | 001-33784 | 10.1.6.1 | 11/3/2017 | ||||||||||||||||
| 10.1.4† | 10-K | 001-33784 | 10.1.7 | 2/22/2018 | ||||||||||||||||
| 10.1.5† | 10-Q | 001-33784 | 10.1.1 | 11/8/2018 | ||||||||||||||||
| 10.2† | 10-Q | 001-33784 | 10.1 | 11/8/2018 | ||||||||||||||||
| 10.2.1† | 10-Q | 001-33784 | 10.1.2 | 11/8/2018 | ||||||||||||||||
| 10.2.2† | 10-Q | 001-33784 | 10.1.3 | 11/8/2018 | ||||||||||||||||
| 10.2.3† | 10-K | 001-33784 | 10.2.3 | 3/4/2019 | ||||||||||||||||
| 10.3† | 10-Q | 001-33784 | 10.3.4 | 11/5/2015 | ||||||||||||||||
| 10.4† | 10-Q | 001-33784 | 10.3.7 | 5/09/2019 | ||||||||||||||||
| 10.4.1† | 10-Q | 001-33784 | 10.3.8 | 5/09/2019 | ||||||||||||||||
| 10.4.2† | 10-K | 001-33784 | 10.4.2 | 2/27/2020 | ||||||||||||||||
| 10.5† | 8-K | 001-33784 | 10.9 | 10/7/2016 | ||||||||||||||||
| 10.6 | 8-K | 001-33784 | 10.1 | 6/27/2019 | ||||||||||||||||
| 10.7 | 10-K | 001-33784 | 10.6 | 3/3/2017 | ||||||||||||||||
| 10.8 | 8-K | 001-33784 | 10.4 | 10/7/2016 | ||||||||||||||||
100
| Incorporated by Reference | ||||||||||||||||||||
Exhibit No. | Exhibit Description | Form | SEC File No. | Exhibit | Filing Date | Filed Herewith | ||||||||||||||
| 10.9 | 8-K | 001-33784 | 10.5 | 10/7/2016 | ||||||||||||||||
| 10.10.1 | 8-K | 001-33784 | 10.1 | 6/19/2018 | ||||||||||||||||
| 10.10.2 | 8-K | 001-33784 | 10.2 | 6/19/2018 | ||||||||||||||||
| 10.11 | 8-K | 001-33784 | 10.1 | 4/7/2020 | ||||||||||||||||
| 10.13 | 8-K | 001-33784 | 10.1 | 5/19/2020 | ||||||||||||||||
| 10.14 | 8-K | 001-33784 | 4.1 | 7/2/2020 | ||||||||||||||||
| 10.15 | 8-K | 001-33784 | 10.1 | 7/2/2020 | ||||||||||||||||
| 10.16 | 8-K | 001-33784 | 2.1 | 12/14/2020 | ||||||||||||||||
| 10.17 | * | |||||||||||||||||||
| 10.18 | * | |||||||||||||||||||
| 21.1 | * | |||||||||||||||||||
| 22.1 | 10-K | 001-33784 | 22.1 | 3/4/2021 | ||||||||||||||||
| 23.1 | * | |||||||||||||||||||
| 23.2 | * | |||||||||||||||||||
| 23.3 | * | |||||||||||||||||||
| 31.1 | * | |||||||||||||||||||
| 31.2 | * | |||||||||||||||||||
| 32.1 | * | |||||||||||||||||||
| 99.1 | * | |||||||||||||||||||
| 101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | * | ||||||||||||||||||
101
| Incorporated by Reference | |||||||||||||||||||||
Exhibit No. | Exhibit Description | Form | SEC File No. | Exhibit | Filing Date | Filed Herewith | |||||||||||||||
| 101.SCH | XBRL Taxonomy Extension Schema Document | * | |||||||||||||||||||
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | * | |||||||||||||||||||
| 101.DEF | XBRL Taxonomy Extension Definition Document | * | |||||||||||||||||||
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document | * | |||||||||||||||||||
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | * | |||||||||||||||||||
Item 16. Form 10-K Summary
Not Applicable.
102
| Successor | |||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| 2017 | |||||||||||||||
| Total revenues | $ | 98,350 | $ | 84,851 | $ | 80,892 | $ | 93,206 | |||||||
| Income (loss) from operations(1)(2) | $ | 50,780 | $ | 23,348 | $ | (16,267 | ) | $ | (18,230 | ) | |||||
| Net income (loss)(1)(2) | $ | 50,808 | $ | 23,499 | $ | (8,485 | ) | $ | (18,760 | ) | |||||
| Income available (loss applicable) to SandRidge Energy, Inc. common stockholders(1)(2) | $ | 50,808 | $ | 23,499 | $ | (8,485 | ) | $ | (18,760 | ) | |||||
| Income available (loss applicable) per share to SandRidge Energy, Inc. common stockholders | |||||||||||||||
| Basic | $ | 1.90 | $ | 0.69 | $ | (0.25 | ) | $ | (0.54 | ) | |||||
| Diluted | $ | 1.90 | $ | 0.69 | $ | (0.25 | ) | $ | (0.54 | ) | |||||
| Predecessor | Successor | |||||||||||||||||||
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Fourth Quarter | ||||||||||||||||
| 2016 | ||||||||||||||||||||
| Total revenues | $ | 90,332 | $ | 99,421 | $ | 104,056 | $ | — | $ | 98,456 | ||||||||||
| Loss from operations(1)(2) | $ | (273,555 | ) | $ | (275,310 | ) | $ | (357,338 | ) | $ | — | $ | (336,345 | ) | ||||||
| Net (loss) income(1)(2)(3) | $ | (313,226 | ) | $ | (515,911 | ) | $ | (404,337 | ) | $ | 2,674,271 | $ | (333,982 | ) | ||||||
| (Loss applicable) income available to SandRidge Energy, Inc. common stockholders(1)(2)(3) | $ | (324,107 | ) | $ | (521,351 | ) | $ | (404,337 | ) | $ | 2,674,271 | $ | (333,982 | ) | ||||||
| (Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders | ||||||||||||||||||||
| Basic | $ | (0.47 | ) | $ | (0.73 | ) | $ | (0.56 | ) | $ | 3.72 | $ | (17.61 | ) | ||||||
| Diluted | $ | (0.47 | ) | $ | (0.73 | ) | $ | (0.56 | ) | $ | 3.72 | $ | (17.61 | ) | ||||||
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| SANDRIDGE ENERGY, INC. | ||||||||
| /s/ Grayson Pranin | ||||||||
| Grayson Pranin | ||||||||
| President, | ||||||||
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Julian Bott, Philip T. WarmanGrayson Pranin and Dustin Crawford,Salah Gamoudi and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Title | Date | |||||||||
| /s/ GRAYSON PRANIN | President, Chief Executive Officer and Chief Operating Officer (Principal Executive Officer) | March 10, 2022 | |||||||||
| Grayson Pranin | |||||||||||
| /s/ | Senior Vice President, | ||||||||||
| Chief Financial Officer and | |||||||||||
Chief Accounting Officer (Principal Financial and Accounting Officer) | |||||||||||
| /s/ | Director | ||||||||||
| /s/ JONATHAN FRATES | Chairman | March 10, 2022 | |||||||||
| Jonathan Frates | |||||||||||
| /s/ JOHN | |||||||||||
| John | |||||||||||
| /s/ | Director | ||||||||||
103
| Incorporated by Reference | ||||||
Exhibit No. | Exhibit Description | Form | SEC File No. | Exhibit | Filing Date | Filed Herewith |
| 2.1 | 8-K | 001-33784 | 2.1 | 1/9/2014 | ||
| 2.2 | 8-A | 001-33784 | 2.1 | 10/4/2016 | ||
| 2.3** | 8-K | 001-33784 | 2.1 | 11/15/2017 | ||
| 3.1 | 8-A | 001-33784 | 3.1 | 10/4/2016 | ||
| 3.2 | 8-A | 001-33784 | 3.2 | 10/4/2016 | ||
| 3.3 | 8-K | 001-33784 | 3.1 | 11/27/2017 | ||
| 4.1 | 8-K | 001-33784 | 4.1 | 10/7/2016 | ||
| 4.2 | 8-K | 001-33784 | 10.6 | 10/7/2016 | ||
| 4.3 | 8-K | 001-33784 | 10.3 | 10/7/2016 | ||
| 4.4 | 8-A | 001-33784 | 10.1 | 10/4/2017 | ||
| 4.5 | 8-K | 001-33784 | 4.1 | 11/27/2017 | ||
| 4.6 | 8-K | 001-33784 | 4.1 | 1/23/2018 | ||
| 10.1† | 8-K | 001-33784 | 10.8 | 10/7/2016 | ||
| 10.1.1† | 10-K | 001-33784 | 10.1.1 | 3/3/2017 | ||
| 10.1.1.1† | 10-Q | 001-33784 | 10.1.1.1 | 11/3/2017 | ||
| 10.1.2† | 10-K | 001-33784 | 10.1.2 | 3/3/2017 | ||
| 10.1.2.1† | 10-Q | 001-33784 | 10.1.2.1 | 11/3/2017 | ||
| 10.1.3† | 10-K | 001-33784 | 10.1.3 | 3/3/2017 | ||
| 10.1.4† | 10-K | 001-33784 | 10.1.4 | 3/3/2017 | ||
| 10.1.4.1† | 10-Q | 001-33784 | 10.1.4.1 | 11/3/2017 | ||
| 10.1.5† | 10-K | 001-33784 | 10.1.5 | 3/3/2017 | ||
| 10.1.6† | 10-Q | 001-33784 | 10.1.6 | 8/7/2017 | ||
| 10.1.6.1† | 10-Q | 001-33784 | 10.1.6.1 | 11/3/2017 | ||
| 10.1.7† | * | |||||
| 10.2.1† | 10-K | 001-33784 | 10.3.1 | 2/27/2015 | ||
| 10.2.2† | 8-K | 001-33784 | 10.1 | 8/5/2015 | ||
| 10.2.3† | 10-K | 001-33784 | 10.3.2 | 2/27/2015 | ||
| 10.2.4† | 10-Q | 001-33784 | 10.3.4 | 11/5/2015 | ||
| 10.2.5† | 8-K | 001-33784 | 10.1 | 2/9/2018 | ||
| 10.3† | 8-K | 001-33784 | 10.9 | 10/7/2016 | ||
| 10.4 | 8-K | 001-33784 | 10.1 | 10/7/2016 | ||
| 10.5 | 8-K | 001-33784 | 10.1 | 2/13/2017 | ||
| 10.6 | 10-K | 001-33784 | 10.6 | 3/3/2017 | ||
| 10.7 | 8-K | 001-33784 | 10.4 | 10/7/2016 | ||
| 10.8 | 8-K | 001-33784 | 10.5 | 10/7/2016 | ||
| 10.9 | 8-K | 001-33784 | 10.2 | 10/7/2016 | ||
| 10.9.1 | 10-K | 001-33784 | 10.9 | 3/3/2017 | ||
| 10.10 | 8-K | 001-33784 | 10.1 | 5/16/2016 | ||
| 10.11 | 8-K | 001-33784 | 10.1 | 12/28/2017 | ||
| 21.1 | * | |||||
| 23.1 | * | |||||
| 23.2 | * | |||||
| 23.3 | * | |||||
| 23.4 | * | |||||
| 31.1 | * | |||||
| 31.2 | * | |||||
| 32.1 | * | |||||
| 99.1 | * | |||||
| 99.2 | * | |||||
| 99.3 | * | |||||
| 101.INS | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | * | ||||
| 101.SCH | XBRL Taxonomy Extension Schema Document | * | ||||
| 101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | * | ||||
| 101.DEF | XBRL Taxonomy Extension Definition Document | * | ||||
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document | * | ||||
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | * | ||||
** Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. SandRidge Energy, Inc., Inc. hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the U.S. Securities and Exchange Commission; provided, however, that SandRidge Energy, Inc. may request confidential treatment pursuant to Rule 24b-2 of the Securities Exchange Act of 1934, as amended, for any schedules so furnished. | ||||||
| † Management contract or compensatory plan or arrangement | ||||||