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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
þANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018 
OR
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to            
Commission File Number: 001-33784
SANDRIDGE ENERGY, INC.
(Exact name of registrant as specified in its charter)

Delaware20-8084793
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)
123 Robert S. Kerr Avenue
Oklahoma City, Oklahoma
73102 
(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 Each ClassName of Each Exchange on Which Registered
Common Stock, $0.001 par valueNew 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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
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 þ No o
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  o
Accelerated filer þ
Non-accelerated filer o 
Smaller reporting company o
Emerging growth company o
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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes ¨ No þ
The aggregate market value of our common stock held by non-affiliates on June 29, 2018 was approximately $539.2 million based on the closing price as quoted on the New York Stock Exchange. As of February 20, 2019, there were 35,687,601 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Company’s definitive proxy statement for the 2019 Annual Meeting of Stockholders, which will be filed with the SEC within 120 days of December 31, 2018, are incorporated by reference in Part III.


SANDRIDGE ENERGY, INC.
2018 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
 
Item Page
PART I
1
1A.
1B.
2
3
4
PART II
5
6
7
7A.
8
9
9A.
9B.
PART III
10
11
12
13
14
PART IV
15
16



GLOSSARY OF TERMS

References in this report to the “Company,” “SandRidge,” “we,” “our,” and “us” mean SandRidge Energy, Inc., including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary. References to the “Successor” or the “Successor Company” relate to SandRidge subsequent to October 1, 2016. References to the “Predecessor” or “Predecessor Company” refer to SandRidge on and prior to October 1, 2016. In addition, the following is a description of the meanings of certain terms used in this report.

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.

2009 Plan. SandRidge Energy, Inc. 2009 Incentive Plan. 

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.

Bankruptcy Petitions. Voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bench. A geological horizon; a distinctive stratum useful for stratigraphic correlation.
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 2018 of $65.56/Bbl for oil and $3.10/Mcf for natural gas, the ratio of economic value of oil to natural gas was approximately 21 to 1, even though the ratio for determining energy equivalency is 6 to 1.
Boe/d. Boe per day.
Bonanza Creek. Bonanza Creek Energy, Inc.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Building Note. Note with a principal amount of $35.0 million, as amended in February 2017, which was secured by first priority mortgages on the Company’s real estate in Oklahoma City, Oklahoma.

Cash Collateral Account. Restricted cash account controlled by the administrative agent to the First Lien Exit Facility.

CBP. Central Basin Platform.

Ceiling limitation. 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.

CO2. Carbon dioxide.

Common Stock. Common stock in the Successor Company.
1

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.
Convertible Notes. Non-interest bearing 0.00% convertible senior secured subordinated notes due 2020.
Convertible Senior Unsecured Notes. 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023.

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

Credit facility. Senior credit facility dated February 10, 2017.

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

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

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

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

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

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural
2

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.
First Lien Exit Facility. $425.0 million reserve-based revolving credit facility entered into on the Emergence Date.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal well. A well that is turned horizontally at depth, providing access to oil and gas reserves at a wide range of angles.
Hydraulic fracturing. Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Hydraulic fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity.
IRS. Internal Revenue Service.
Lease. A contract in which the owner of minerals gives a company or working interest owner temporary and limited rights to explore for, develop, and produce minerals from the property, or; any transfer where the owner of a mineral interest assigns all or a part of the operating rights to another party but retains a continuing nonoperating interest in production from the property.
MBbls. Thousand barrels of oil or other liquid hydrocarbons.
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.
Netherland Sewell. Netherland, Sewell & Associates, Inc.

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

NYMEX. The New York Mercantile Exchange.

NYSE. New York Stock Exchange.

Occidental. Occidental Petroleum Corporation.

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

Permian Divestiture. The November 1, 2018 sale of substantially all of the Company's oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, along with 13,125,000 common units representing a 25% equity interest in the Permian Trust to an independent third party.

Permian Trust. SandRidge Permian Trust.

Plan. Debtors’ joint plan of reorganization, as amended.

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Poison Pill. Agreement with American Stock Transfer & Trust Company, LLC on November 26, 2017, as amended by the First Amendment to the Stockholder Rights Agreement dated January 22, 2018.

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.

Predecessor 2016 Period. Period from January 1, 2016, through October 1, 2016.

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% and PV-9 is calculated using an annual discount rate of 9%.
Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities that become part of the cost of oil and natural gas produced.
Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Prospect. A specific geographic area that, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed reserves. Reserves that are both proved and developed.
Proved oil, natural gas and NGL reserves. Those quantities of oil, natural gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. 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-9. See “Present value of future net revenues” above.
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.

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

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

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.

Senior credit facility. Predecessor Company's pre-petition senior secured revolving credit facility.

Senior Secured Notes. Collectively, the 8.75% Senior Secured Notes due 2020 and the 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC.

Senior Unsecured Notes. Collectively, the 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022 and 7.5% Senior Notes due 2023.

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, 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.

Successor 2016 Period. Period after October 1, 2016 through December 31, 2016.

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.
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.
Unsecured Notes. Collectively, the Convertible Senior Unsecured Notes and the Senior Unsecured Notes.
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.
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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.
WTI. West Texas Intermediate.

WTO. West Texas Overthrust.


Cautionary Note Regarding Forward-Looking Statements

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

GENERAL

We are an oil and natural gas company, organized in 2006 as a Delaware corporation, with a principal focus on exploration and production activities in the U.S. Mid-Continent and North Park Basin of Colorado.

As of December 31, 2018, we had an interest in 1,777 gross (1,095.8 net) producing wells, approximately 1,272 of which we operate, and approximately 777,000 gross (571,000 net) total acres under lease. As of December 31, 2018, we had two rigs drilling in the Mid-Continent and one rig drilling in the North Park Basin. Total estimated proved reserves as of December 31, 2018, were 160.2 MMBoe, of which approximately 58% were proved developed.

Our principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and our telephone number is (405) 429-5500. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available free of charge on our website at www.sandridgeenergy.com as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. Any materials that we have filed with the SEC may be accessed via the SEC’s website address at www.sec.gov.

Reorganization Under Chapter 11 and Emergence from Bankruptcy

On May 16, 2016, the Debtors filed Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan, and the Debtors’ subsequently emerged from bankruptcy on the Emergence Date. The Company’s Chapter 11 reorganization and related matters are addressed in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Note 1 - Voluntary Reorganization under Chapter 11 Proceedings” and “Note 2 - Summary of Significant Accounting Policies” to the accompanying consolidated financial statements contained in Item 8. “Financial Statements and Supplementary Data.”

Fresh Start Accounting

Upon emergence from Chapter 11, we elected to apply fresh start accounting effective October 1, 2016, to coincide with the timing of our normal fourth quarter reporting period, which resulted in SandRidge becoming a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements after October 1, 2016 are not comparable with the financial statements prior to that date. References to the “Successor” or the “Successor Company” relate to SandRidge subsequent to October 1, 2016. References to the “Predecessor” or “Predecessor Company” refer to SandRidge on and prior to October 1, 2016.

Our Mission

SandRidge Energy’s mission is to deliver a competitive and sustainable rate of return to its shareholders by developing, acquiring, and exploring for oil and natural gas resources. The Company’s asset portfolio is positioned to deliver long-term value to shareholders through its inventory of development opportunities in the NW STACK and Mississippian Lime Plays in Oklahoma and the Niobrara in North Park Basin, Colorado. We intend to acquire additional assets in the United States to lower the break-even costs of our investment portfolio and to ensure we deliver competitive and sustainable returns.

Our Business Strategy

SandRidge’s business strategy is to acquire, explore for, and develop hydrocarbon resources in the United States; focus on financial discipline, flexibility, and value creation; and ensure health, safety, and environmental excellence while demonstrating the Company’s core values. We will accomplish this strategy by focusing on the following key objectives:

Attract and retain the best people. Achieving our mission will only be possible through our employees. It is therefore critical to have compensation, development, and human resource programs that attract, retain and motivate the types of people we need to succeed.

Pursue operational excellence with a sense of urgency. We plan to deliver low cost, consistent and efficient execution of our drilling campaigns, work programs and operations. We will execute our operations in a safe and environmentally
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responsible manner, quickly and efficiently apply advanced technologies, and continuously seek ways to reduce our operating cash costs on a per barrel basis. Operational excellence is the foundation upon which we will achieve our mission.

Invest in high-margin, high rate-of-return projects. The key to achieving our mission will be to prioritize our work programs and allocate our capital to projects that deliver high returns. Additionally, we will assess the full range of uncertainty and thoroughly understand the risks associated with every oil and gas investment so we can accurately and consistently predict our results.

Continuously upgrade our investment portfolio to reduce break-even costs. We will actively pursue accretive acquisitions, mergers and dispositions to improve our margins and returns and to reduce the break-even costs of our portfolio of investment opportunities. This component of our strategy is key to delivering competitive returns to our shareholders on a sustainable basis.

Protect our balance sheet and demonstrate financial discipline. Having the ability to capitalize on opportunities when they arise and investing to generate competitive and sustainable returns requires the financial flexibility that can only be achieved through the financial discipline of balancing our growth plans with the preservation of our balance sheet. To accomplish this we will adhere to the financial principles that lead to the responsible use of leverage,  hedging strategies that are complementary to our use of debt and help ensure the necessary cash flow to sustain our capital programs, and financial strategies that focus on delivering competitive debt-adjusted per share returns.

Acquisitions and Divestitures of Oil and Gas Properties

2018 Divestiture and Acquisition

Divestiture of Permian Basin Properties. On November 1, 2018, we sold substantially all of our oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with all of our 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced our asset retirement obligations by approximately $26.9 million. The CBP assets and interest in the Permian Trust include 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with the Company's CBP operations. As a result of this divestiture, we will no longer have any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between our capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale.

Acquisition of Oil and Natural Gas Interests. On November 2, 2018, the Company acquired an interest in certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million. The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which are operated by the Company, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in the Company's saltwater gathering and disposal system in the Mississippian Lime. This acquisition is expected to increase total production for existing producing properties by approximately 10%.

2017 Acquisition and Divestitures

NW STACK. On February 10, 2017, the Company 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.

Oil and Natural Gas Property Divestitures. In 2017, the Company divested various non-core oil and natural gas properties for approximately $17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.

2016 Divestiture and Release from Treating Agreement

In January 2016, we transferred ownership of substantially all of our oil and natural gas properties and midstream assets located in the Piñon field in the WTO and $11.0 million in cash to a wholly owned subsidiary of Occidental and were released from all past, current and future claims and obligations under an existing 30-year treating agreement with Occidental.
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In connection with this transfer, the Predecessor Company recognized a loss of approximately $89.1 million upon termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field and reduced asset retirement obligations associated with these oil and natural gas properties by $34.1 million.

PRIMARY BUSINESS OPERATIONS

Our primary operations are the exploration, development and production of oil and natural gas. The following table presents information concerning our exploration and production activities by geographic area of operation as of December 31, 2018.
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-Continent110.9 29.9 10.2 643,015 445,189 $58.4 
North Park Basin49.3 3.8 35.5 123,135 116,973 109.4 
Other— — — 10,969 8,575 2.5 
Total160.2 33.7 13.0 777,119 570,737 $170.3 
____________________
1.Average daily net production for the month of December 2018.
2.Estimated net proved reserves as of December 31, 2018 divided by production for the month of December 2018, annualized.
3.Capital expenditures for the year ended December 31, 2018, on an accrual basis.

Properties

Mid-Continent

We held interests in approximately 643,000 gross (445,000 net) leasehold acres located primarily in Oklahoma and Kansas at December 31, 2018. Associated proved reserves at December 31, 2018 totaled 110.9 MMBoe, 77.6% of which were proved developed reserves. Our interests in the Mid-Continent as of December 31, 2018 included 1,739 gross (1,057.8 net) producing wells with an average working interest of 61%. We had two rigs operating in the Mid-Continent as of December 31, 2018, which were drilling horizontal wells. One of the rigs was drilling under the drilling participation agreement described below. At December 31, 2018, our Mid-Continent properties included an inventory of 90 operated proved undeveloped laterals. Additionally, we estimate there are several hundred undeveloped probable horizontal well locations. During 2018, we completed a total of 21 horizontal producing wells in this area, which consisted primarily of SRLs.

NW STACK. The Meramec and Osage formations are the primary targets in the STACK play of Blaine and Kingfisher Counties, and are currently being drilled using horizontal well technology in a play area called the NW STACK in Garfield, Major, Dewey, and Woodward Counties. These formations are Mississippian in age, lying above the Woodford Shale formation and below Chester (if present) and Pennsylvanian formations. The Meramec is composed of interbedded shales, sands, and carbonates while the Osage is composed of low porosity, fractured limestone and chert. The top of these target formations ranges in depth from about 5,800 feet at the northern edge of the basin to greater than 14,000 feet toward the interior of the basin. Meramec formation thickness ranges from about 50 feet to over 400 feet and the Osage formation thickness ranges from about 450 to 1,400 feet. The Woodford Shale is the primary hydrocarbon source for both the Meramec and Osage, although the organic content in the Meramec Shale may provide a self-sourcing component as well. Similar to the STACK, there is an over-pressured area and normally pressured area in the NW STACK. Significant industry activity in the NW STACK has established both the Meramec and Osage as productive reservoirs with successful wells. We completed 17 wells in the Meramec formation during 2018 and no Osage wells. Of our total Mid-Continent acreage at December 31, 2018, approximately 116,000 gross (65,000 net) acres are associated with the NW STACK play area.

In the third quarter of 2017, we entered into a $200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of our undeveloped leasehold acreage within the Meramec formation in the NW STACK. Under this agreement, the Counterparty is paying 90% of the net drilling and completion costs, up to $100.0 million in the first tranche, in exchange for an initial 80% net working interest in each new well, subject to certain reversionary hurdles. As a result, we are receiving a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells. We operate all of the wells developed under this agreement
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and retain sole discretion as to the number, location and schedule of wells drilled. The Counterparty also has the option to fund a second $100.0 million tranche, subject to mutual agreement. See "Operational Activities" included in Item 7 of this report for further discussion of the drilling participation agreement.

Mississippian Lime Formation. The Mississippian Lime formation is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and southern Kansas, and is a target for exploration and development within the Mid-Continent. The top of this formation is encountered between approximately 4,000 and 7,000 feet and stratigraphically between various formations of Pennsylvanian age and the Devonian-aged Woodford Shale formation. The Mississippian formation is approximately 350 to 650 feet in gross thickness across our lease position and has targeted porosity zone(s) ranging between 20 and 150 feet in thickness. At December 31, 2018, we had approximately 527,000 gross (381,000 net) acres under lease and 1,289 gross (864.8 net) producing wells in the Mississippian formation. We completed two horizontal wells, including one XRL and one SRL, in the Mississippian Lime formation in 2018.

North Park Basin

Our North Park Basin properties consisted of approximately 123,000 gross (117,000 net) acres, and 38 gross and net producing wells with a working interest of 100%, at December 31, 2018. Associated proved reserves at December 31, 2018 totaled approximately 49.3 MMBoe, of which 12.7% were proved developed reserves. The North Park Basin acreage is located in north central Colorado and, similar to the DJ Basin next to Colorado’s Front Range, has multiple potential pay targets in addition to the Niobrara Shale play where our activity is currently focused. Although untested, zones shallower and deeper than the Niobrara have indications of potentially commercial hydrocarbons. The Niobrara Shale is characterized by stacked pay benches at depths of 5,500 to 9,000 feet with overall reservoir thickness over 450 feet. Based on our delineation drilling on acreage inside and outside federal units, we are developing a proved area where we have 193 proved undeveloped lateral locations. Across our entire acreage position, we estimate there are approximately 1,000 undeveloped probable horizontal lateral locations. We had one rig operating in the North Park Basin which was drilling a horizontal well as of December 31, 2018. We completed a total of eight horizontal producing wells, including seven XRLs and one SRL, in this area during 2018.

Proved Reserves

The portion of a reservoir considered to contain proved reserves includes (i) the portion identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil, natural gas or NGLs on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Existing economic conditions include prices, costs, operating methods and government regulations existing at the time the reserve estimates are made. SEC prices are used to determine proved reserves, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. See further discussion of prices in “Risk Factors” included in Item 1A of this report.

Preparation of Reserves Estimates

Over 90% of the proved oil, natural gas and NGL reserves disclosed in this report are based on reserve estimates determined and prepared by independent reserve engineers primarily using decline curve analysis to determine the reserves of individual producing wells. A small portion of the proved reserves disclosed in this report were determined by internal reserve engineers. To establish reasonable certainty with respect to our estimated proved reserves, the independent and internal reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area. These wells were considered to be analogous based on production performance from the same formation and completions using similar techniques. 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 data available. 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:

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•the quality and quantity of available data and the engineering and geological interpretation of that data;
•estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
•the accuracy of economic assumptions; and
•the judgment of the personnel preparing the estimates.

SandRidge’s Senior Vice President—Reserves, Technology and Business Development is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering with over 30 years of practical industry experience, including over 30 years of estimating and evaluating reserve information. He has also been a certified professional engineer in the state of Oklahoma since 2007 and a member of the Society of Petroleum Engineers since 1980.

SandRidge’s reserve engineers monitor well performance and make reserve estimate adjustments as necessary to ensure the most current information is reflected. The information used to prepare reserve estimates includes production histories as well as other geologic, economic, ownership and engineering data. The Corporate Reserves department currently has a total of six full-time employees, comprised of four degreed engineers and two engineering and business analysts with a minimum of a four-year degree in mathematics, finance or other business or science field.

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, the Corporate Reserves department follows comprehensive SEC-compliant internal controls and policies to determine, estimate and report proved reserves including:
•confirming that we include reserves estimates for all properties owned and that they are based upon proper working and net revenue interests;
•ensuring the information provided by other departments within the Company such as Accounting is accurate;
•communicating, collaborating, and analyzing with technical personnel in our business units;
•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.

Each quarter, the Senior Vice President—Reserves, Technology and Business Development presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives. Additionally, the five year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, and the Senior Vice President - Reserves, Technology and Business Development.

The Corporate Reserves department works closely with independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.

The percentage of total proved reserves prepared by each of the independent petroleum consultants is shown in the table below.
 December 31,
 201820172016
Cawley, Gillespie & Associates, Inc.51.6 %62.6 %72.0 %
Ryder Scott Company, L.P.43.5 %29.0 %18.4 %
Netherland, Sewell & Associates, Inc.— %3.8 %3.6 %
Total95.1 %95.4 %94.0 %

The remaining 4.9%, 4.6% and 6.0% of estimated proved reserves as of December 31, 2018, 2017 and 2016, respectively, were based on internally prepared estimates, primarily for the Mid-Continent area.

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Copies of the reports issued by our independent reserve consultants with respect to our oil, natural gas and NGL reserves for over 90% of all geographic locations as of December 31, 2018 are filed with this report as Exhibits 99.1 and 99.2. The geographic location of our estimated proved reserves prepared by each of the independent reserve consultants as of December 31, 2018 is presented below.
Geographic Locations—by Area by State
Cawley, Gillespie & Associates, Inc.Mid-Continent—KS, OK
Ryder Scott Company, L.P.North Park Basin—CO, Mid-Continent—OK

The qualifications of the technical personnel at each of these firms primarily responsible for overseeing the firm’s preparation of the Company’s reserves estimates included in this report are set forth below. These qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

Cawley, Gillespie & Associates, Inc.
•more than 25 years of practical experience in the estimation and evaluation of petroleum reserves;
•a registered professional engineer in the state of Texas; and
•Bachelor of Science Degree in Petroleum Engineering.

Ryder Scott Company, L.P.
•more than 30 years of practical experience in the estimation and evaluation of petroleum reserves;
•a registered professional engineer in the states of Alaska, Colorado, Texas and Wyoming; and
•Bachelor of Science Degree in Petroleum Engineering and MBA in Finance;

Netherland, Sewell & Associates, Inc.
•practicing consultant in petroleum engineering since 2013 and over 14 years of prior industry experience;
•licensed professional engineers in the state of Texas; and
•Bachelor of Science Degree in Chemical Engineering

Reporting of Natural Gas Liquids

NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2018, NGLs comprised approximately 18% of total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where we have contracts in place for the extraction and sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels based on a conversion rate of 42 gallons per barrel. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. 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.

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Reserve Quantities, PV-10 and Standardized Measure

The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2018, 2017 and 2016, over 90% of which were prepared by independent reserve engineers. The reserve reports were based on our drilling schedule at the time year-end reserve estimates were prepared. Our year-end 2018 PUD development plan established that 100% of our current proved undeveloped reserves will be developed within five years from when they were originally recorded. See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.
 December 31,
 201820172016
Estimated Proved Reserves(1)
Developed
Oil (MMBbls)18.7 25.9 25.9 
NGL (MMBbls)22.3 29.9 29.3 
Natural gas (Bcf)307.9 408.0 393.0 
Total proved developed (MMBoe)92.3 123.8 120.7 
Undeveloped
Oil (MMBbls)45.3 35.9 27.0 
NGL (MMBbls)5.9 4.4 4.2 
Natural gas (Bcf)100.0 80.9 71.8 
Total proved undeveloped (MMBoe)67.9 53.8 43.2 
Total Proved
Oil (MMBbls)64.0 61.8 52.9 
NGL (MMBbls)28.2 34.3 33.5 
Natural gas (Bcf)407.9 488.9 464.8 
Total proved (MMBoe)160.2 177.6 163.9 
Standardized Measure of Discounted Net Cash Flows (in millions)(2)

$1,045.6 $749.3 $438.4 
PV-10 (in millions)(3)$1,045.6 $749.3 $438.4 
____________________
1. Estimated proved reserves, PV-10 and Standardized Measure were determined using SEC prices, and do not reflect actual prices received or current market prices. All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table below. 
 Index prices (a)
Weighted average 
wellhead prices (b) 
 Oil
(per Bbl)		Natural gas
(per Mcf)
Oil
(per Bbl)
NGL
(per Bbl)
Natural gas
(per Mcf)
December 31, 2018$65.56 $3.10 $60.86 $25.62 $1.77 
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 
____________________
a.Index prices are based on average West Texas Intermediate (“WTI”) Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.
b.Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, and regional price differentials.

2. Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes. At December 31, 2018, 2017 and 2016, the difference between the standardized measure and PV-10 was insignificant due to an excess of tax basis in oil and natural gas properties over projected undiscounted future cash flows from our proved reserves.

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3. PV-10 is a non-GAAP financial measure. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our oil and natural gas properties. PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. The following table provides a reconciliation of our Standardized Measure to PV-10:
 December 31,
 201820172016
 (In millions)
Standardized Measure of Discounted Net Cash Flows$1,045.6 $749.3 $438.4 
Present value of future income tax discounted at 10%— — — 
PV-10$1,045.6 $749.3 $438.4 

Proved Reserves - Mid-Continent. Proved reserves in the Mid-Continent, primarily the Mississippian formation, decreased from 130.6 MMBoe at December 31, 2017 to 110.9 MMBoe at December 31, 2018. This reserve reduction is due primarily to downward revisions of 22.5 MMBoe of late life reserves due to (i) an increase in estimated future workover and improved recovery costs that shortened the economic lives of these properties, and (ii) 10.2 MMBoe of negative revisions to prior estimates stemming from changes in well performance, and 2018 production totaling 11.0 MMBoe. Additional reserve decreases amounting to 6.2 MMBoe were the result of wells being shut-in during 2018, changes to lease operating costs and other reserve parameters. Partially offsetting these reductions were the acquisition of 15.4 MMBoe in reserves, 10.3 MMBoe of reserve extensions and discoveries, largely associated with successful drilling in our NW STACK play and a 4.6 MMBoe increase associated with the increase in year-end SEC commodity pricing. 

Proved Reserves - North Park Basin. Our North Park Basin proved reserves in the Niobrara increased from 40.2 MMBoe at December 31, 2017 to 49.3 MMBoe at December 31, 2018. This increase is due to the results of our development drilling program which resulted in 9.0 MMBoe of reserve extensions and discoveries associated with proved undeveloped reserves at an increased well density, 4.5 MMBoe in upward revisions primarily due to converting undeveloped well locations from SRLs to planned XRLs, and a 1.1 MMBoe increase associated with the increase in year-end SEC commodity pricing. These increases were partially offset by downward revisions of 3.7 MMBoe due to an increase in anticipated future lease operating expenses and project schedule changes that lowered estimated ultimate recoveries from these properties, 2018 production of 1.0 MMBoe, and other reductions amounting to 0.8 MMBoe. Our Niobrara proved developed reserves are attributed to 38 horizontal producing wells. Reservoir characteristics of the Niobrara in the North Park Basin are similar to those of the Niobrara in the DJ Basin, consisting of multiple stratigraphic benches. In the North Park Basin, production performance and reservoir data gathered from Niobrara producing wells confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. Using the performance of the proved developed producing wells, proved undeveloped reserves were recorded for 29 sections of the 35 section proved development area at a well density of eight wells per section and 12 wells per section for the remaining six sections. Delineation drilling to determine optimal well spacing is ongoing, although early results indicate 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,
201820172016
Reserves converted from proved undeveloped to proved developed (MMBoe)
4.2 1.1 6.8 
Drilling capital expended to convert proved undeveloped reserves to proved developed reserves (in millions)
$63.2 $21.0 $64.5 

Total estimated proved undeveloped reserves were 67.9 MMBoe at December 31, 2018, which is an increase of 14.1 MMBoe from the prior year. This increase is primarily due to 18.0 MMBoe from extensions and discoveries which consisted primarily of 8.5 MMBoe in the North Park Basin from increased well density and successful development drilling in the Niobrara shale, and 9.5 MMBoe in the Mid-Continent from horizontal drilling in our NW STACK play. These extensions were offset by 4.2 MMBoe of PUD conversions. 

Total estimated proved undeveloped reserves as of December 31, 2017 were 53.8 MMBoe, an increase of 10.6 MMBoe from the prior year. Reserves added from extensions and discoveries totaled 14.7 MMBoe, which consisted of 10.1 MMBoe in North Park from horizontal wells drilled in the Niobrara Shale, and 4.6 MMBoe in the Mid-Continent from horizontal drilling in our NW STACK play. These extensions were offset by 137 MBoe of proved undeveloped reserves at
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December 31, 2016 that were converted to proved developed reserves during 2017, and net downward revisions of 4.0 MMBoe primarily due to removing PUDs attributable to expiring Mid-Continent undeveloped acreage outside of our NW STACK play that was not scheduled to be developed prior to lease expiry. Approximately 1.0 MMBoe of proved undeveloped reserves were booked and converted during the year 2017.

Total estimated proved undeveloped reserves were 43.2 MMBoe at December 31, 2016, which is a decrease of 20.9 MMBoe from the prior year, primarily due to downward revisions associated with lower prices that negatively impact economic viability of certain wells and recovery of estimated reserves. Reserves added from extensions and discoveries totaled 5.5 MMBoe, 3.2 MMBoe in the Mid-Continent as a result of horizontal drilling and 2.3 MMBoe in the North Park Basin from horizontal wells drilled in the Niobrara Shale. These extensions were offset by 5.2 MMBoe of proved undeveloped reserves at December 31, 2015 that were converted to proved developed reserves during 2016. Approximately 1.6 MMBoe of proved undeveloped reserves were booked and converted during the year 2016.

For additional information regarding changes in proved reserves during each of the three years ended December 31, 2018, 2017 and 2016 see “Note 22—Supplemental Information on Oil and Natural Gas Producing Activities” to the consolidated financial statements in Item 8 of this report.

Significant Fields 

Oil, natural gas and NGL production for fields containing more than 15% of our total proved reserves at each year end are presented in the table below. The Mississippian Lime Horizontal field and the Niobrara field each contained more than 15% of total proved reserves at December 31, 2018, 2017 and 2016.

 
Oil
(MBbls)
NGL (MBbls)
Natural Gas
(MMcf)
Total
(MBoe)
Year Ended December 31, 2018
Mississippian Lime Horizontal1,558 2,477 31,663 9,312 
Niobrara1,034 — — 1,034 
Year Ended December 31, 2017
Mississippian Lime Horizontal2,382 2,995 38,834 11,849 
Niobrara673 — — 673 
Year Ended December 31, 2016
Mississippian Lime Horizontal5,029 4,357 56,894 18,868 
Niobrara500 — — 500 

Mississippian Lime Horizontal Field. The Mississippian Lime Horizontal Field is located on the Anadarko Shelf in northern Oklahoma and Kansas and produces from the Mississippian formation. Our interests in the Mississippian Lime Horizontal Field as of December 31, 2018 included 1,289 gross (864.8 net) producing wells and a 67% average working interest in the producing area.

Niobrara Field. The Niobrara field is located in Colorado and produces from the Niobrara Shale. Currently only oil is marketed while evaluation of midstream options for gas processing and marketing is ongoing. Field testing of gas processing techniques to extract liquids and convert gas to liquids is underway. Our interests in the Niobrara Field as of December 31, 2018, included 38 gross and net producing wells with a 100% average working interest in the producing area.


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Production and Price History

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

SuccessorPredecessor

Year Ended December 31,

Year Ended December 31,
Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,
2018201720162016
Production data (in thousands)
Oil (MBbls)3,477 4,157 1,214 4,315 
NGL (MBbls)2,829 3,376 999 3,358 
Natural gas (MMcf)36,175 44,237 12,771 44,124 
Total volumes (MBoe)12,335 14,906 4,342 15,027 
Average daily total volumes (MBoe/d)33.8 40.8 47.7 54.6 
Average prices—as reported(1)
Oil (per Bbl)$61.73 $48.72 $47.03 $36.85 
NGL (per Bbl)$23.72 $18.16 $14.77 $12.67 
Natural gas (per Mcf)$1.85 $2.09 $2.07 $1.78 
Total (per Boe)$28.27 $23.90 $22.64 $18.63 
Expenses per Boe
Production costs(2)$7.12 $6.64 $5.69 $8.49 
__________________
1.Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.
2.Represents production costs per Boe excluding production and ad valorem taxes.

Productive Wells

The following table presents the number of productive wells in which we owned a working interest at December 31, 2018. We operate substantially all of our wells. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing wells in which we have a working interest and net wells are the sum of the fractional working interests owned in gross wells.
 OilNatural GasTotal
 GrossNetGrossNetGrossNet
Area
Mid-Continent1,482 936.3 257 121.5 1,739 1,057.8 
North Park Basin38 38.0 — — 38 38.0 
Total1,520 974.3 257 121.5 1,777 1,095.8 

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Drilling Activity

The following table presents information with respect to wells completed during the periods indicated. This information is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. As of December 31, 2018, we had 11 gross (9.3 net) operated wells drilling, completing or awaiting completion.
 201820172016
 GrossNetGrossNetGrossNet
Completed Wells
Development
Productive29 15.5 22 16.4 32 27.0 
Dry— — — — — — 
Total29 15.5 22 16.4 32 27.0 
Exploratory
Productive— — 1 1.0 — — 
Dry— — — — — — 
Total— — 1 1.0 — — 
Total
Productive
29 15.5 23 17.4 32 27.0 
Dry
— — — — — — 
Total29 15.5 23 17.4 32 27.0 

We had two third-party rigs operating on our Mid-Continent acreage, and one rig operating on our North Park Basin acreage at December 31, 2018.

Developed and Undeveloped Acreage

The following table presents information regarding our developed and undeveloped acreage at December 31, 2018:
 Developed AcreageUndeveloped Acreage
 GrossNetGrossNet
Area
Mid-Continent529,517 386,027 113,498 59,162 
North Park Basin13,652 13,647 109,483 103,326 
Other1,443 391 9,526 8,184 
Total544,612 400,065 232,507 170,672 

Many of the leases included in the undeveloped acreage above will expire at the end of their respective primary terms. To prevent expiration, we may exercise our contractual rights to pay delay rentals to extend the terms of leases we value, or establish production from the leasehold acreage prior to expiration, which will keep the lease from expiring until production has ceased.

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As of December 31, 2018, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows:
 Acres Expiring
 GrossNet
Twelve Months Ending
December 31, 201941,900 29,938 
December 31, 202025,744 14,143 
December 31, 20214,735 3,352 
December 31, 2022 and later3,678 1,886 
Other(1)156,450 121,353 
Total232,507 170,672 
____________________
1.Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.

The acreage due to expire during the twelve months ending December 31, 2019, includes approximately 24,629 gross (15,163 net) acres in the Mid-Continent and 9,949 gross (7,453 net) acres in the North Park Basin.

Marketing and Customers

We sell our oil, natural gas and NGLs to a variety of customers, including utilities, oil and natural gas companies and trading and energy marketing companies. We had three customers that individually accounted for more than 10% of our total revenue during the 2018 period. See “Note 2—Summary of Significant Accounting Policies” to the consolidated financial statements in Item 8 of this report for additional information on our major customers. The number of readily available purchasers in the areas where we sell our production makes it unlikely that the loss of a single customer would materially affect our sales. We do not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements.

Title to Properties

As is customary in the oil and natural gas industry, we conduct a preliminary review of the title to our properties. Prior to commencing drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects typically at our expense. In addition, prior to completing an acquisition of producing oil and natural gas assets, we perform title reviews on the most significant leases and depending on the materiality of properties, may obtain a drilling title opinion or review previously obtained title opinions. To date, we have obtained drilling title opinions on substantially all of our producing properties and believe that we have good and defensible title to our producing properties. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe does not materially interfere with the use of, or affect the carrying value of the properties.

COMPETITION

We compete with major oil and natural gas companies and independent oil and natural gas companies for leases, equipment, personnel and markets for the sale of oil, natural gas and NGLs. We believe our leasehold acreage position, geographic concentration of operations and technical and operational capabilities enable us to compete effectively with other exploration and production operations. However, the oil and natural gas industry is intensely competitive. See “Item 1A. Risk Factors” for additional discussion of competition in the oil and natural gas industry.

Oil, natural gas and NGLs compete with other forms of energy available to customers, including alternate forms of energy such as electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas and NGLs or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil, natural gas and NGLs.


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SEASONAL NATURE OF BUSINESS

Generally, demand for natural gas decreases during the summer months and increases during the winter months and demand for oil peaks during the summer months. Certain natural gas purchasers utilize natural gas storage facilities and acquire some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives, delay the installation of production facilities, and increase competition for equipment, supplies and personnel during certain times of the year, which could lead to shortages and increase costs or delay operations.

ENVIRONMENTAL REGULATIONS

General

Our oil and natural gas exploration, development 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, and the protection of the environment and natural resources. Numerous governmental entities, including the EPA and analogous state and local agencies, (and, under certain laws, private individuals) have the power to enforce compliance with these laws and regulations and any permits issued under them. These laws and regulations may, among other things: (i) require permits to conduct exploration, drilling, water withdrawal, wastewater disposal and other production related activities; (ii) govern the types, quantities and concentrations of substances that may be disposed or released into the environment or injected into formations in connection with drilling or production activities, and the manner of any such disposal, release, or injection; (iii) limit or prohibit construction or drilling activities or require formal mitigation measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; (iv) require investigatory and remedial actions to mitigate pollution conditions arising from the Company’s operations or attributable to former operations; (v) impose safety and health restrictions designed to protect employees 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. We may be unable to pass on increased 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.

Hazardous Substances and Wastes

We currently own, lease, or operate, and in the past have owned, leased, or operated, properties that have been used in the exploration and production of oil and natural gas. We believe we have utilized operating and disposal practices that were standard in the industry at the applicable time, but hazardous substances, hydrocarbons, and wastes may have been disposed or released on, from or under the properties owned, leased, or operated by us or on or under other locations where these substances and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose storage treatment and disposal or release of hazardous substances, hydrocarbons, and wastes were not under our control. These properties and the substances or wastes disposed or released on them may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), the federal Resource Conservation and Recovery Act, (“RCRA”), and analogous state laws. Under these laws, we could be required to remove or remediate previously
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disposed substances or wastes (including substances or wastes disposed of or released by prior owners or operators), to investigate and clean up contaminated property, to perform remedial 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” 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. Despite the so-called “petroleum exclusion,” certain products used in the course of our operations may be regulated as CERCLA hazardous substances. To date, no Company-owned or operated site has been designated as a Superfund site, and we have not been identified as a responsible party for any Superfund site.

We also generate wastes that are subject to the requirements of RCRA and comparable state statutes. RCRA imposes strict “cradle-to-grave” requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced waters and other wastes associated with the exploration, production and/or development of oil and natural gas, including naturally-occurring radioactive material, if properly handled, are currently excluded from regulation as hazardous wastes under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste requirements. However, it is possible that these wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the 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 the 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. 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 Standard for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare. The EPA was required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017, but missed the deadline. Subsequently, in November 2017, the EPA published a list of areas that are in compliance with the new ozone standards and separately in December 2017 issued responses to state recommendation for designating non-attainment areas. States then had the opportunity to submit new air quality monitoring to the EPA prior to the EPA finalizing any non-attainment designations. While the EPA has determined that all counties in which we operate are in attainment with the new ozone standard, these determinations may be revised in the future. With the EPA lowering the ground-level ozone standard, certain states may be required to implement more stringent regulations, which could apply to 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 other air pollution control and permitting requirements has the
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potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant.

Water Discharges

The federal Water Pollution Control Act, 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 EPA issued a final rule in September 2015 that attempts to clarify the federal jurisdictional reach over waters of the United States. The EPA and the Corps then proposed a rulemaking in June 2017 to repeal the June 2015 rule and also announced their intent to issue a new rule defining the CWA’s jurisdiction. The EPA and the Corps issued a final rule in January 2018 staying implementation of the 2015 rule for two years. Subsequently, on December 11, 2018, the EPA and the Corps proposed a new rule defining the CWA’s jurisdiction. A nationwide patchwork of litigation and court rulings developed regarding the rules. At this time, due to varied court rulings, the 2015 rule is effective in some states, while the agencies’ decision to delay implementation of the 2015 rule is effective in other states. If finalized, the 2018 proposed rule would apply nationwide, replacing the national patchwork of CWA jurisdictional applicability. Additionally, if finalized, it is possible that the 2018 proposed rule will be challenged. The scope of the CWA’s jurisdiction likely will remain fluid until a final regulatory determination is made and subsequent litigation, if any, is completed. To the extent a rule ultimately promulgated expands the scope of the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities. Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.

Finally, the Oil Pollution Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and/or the CWA include inspection and maintenance programs to minimize spills from oil storage and conveyance systems; the use of secondary containment systems to prevent spills from reaching nearby water bodies; proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill; and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. We have developed and implemented SPCC plans for properties as required under the CWA.

Subsurface Injections

Underground injection operations performed by us are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although the Company monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property damages and personal injuries. Some states have considered laws mandating flowback and produced water recycling. Other states have undertaken studies to assess the feasibility of recycling produced water on a large scale. For example, in July 2018, the EPA partnered with New Mexico to assess alternatives to the immediate disposal of wastewater from exploration and production activities by reusing it or treating it for reintroduction into the hydrologic cycle or both, and to propose potential regulations related thereto. If such laws are adopted in areas where we conduct operations, our operating costs may increase significantly.

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Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has issued rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for wells within areas of interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents. For example, in February 2016, the OCC issued a plan to reduce disposal well volume in the Arbuckle formation by 40 percent, covering approximately 5,281 square miles and 245 disposal wells injecting wastewater into the Arbuckle formation. In the plan, the OCC identified 76 SandRidge-operated disposals wells, prescribed a four stage volume reduction schedule and set April 30, 2016 as the final date for compliance with the tiered volume reduction plan. In March 2016, the OCC reduced the injection volume of additional Arbuckle disposal wells, including wells we operate. Following earthquakes in August, September and November 2016, the OCC and the EPA further limited the disposal volumes that can be disposed in Arbuckle wells, although these actions did not cover our disposal wells. While induced seismic events generally decreased in 2017, the OCC expanded restrictions on the use of existing Arbuckle disposal wells and imposed new reporting requirements related to disposal volumes on wells injecting produced water into the Arbuckle formation. In February 2018, the OCC instituted a new protocol to further address seismicity in the Sooner Trend Anadarko Basin Canadian and Kingfisher County and South Central Oklahoma Oil Province Plays which requires various actions, such as a pause in operations for several hours, when certain seismic data is observed. Such requirements may reduce the productivity of our operations in relevant areas.

Additionally, the Governor of Kansas has established a task force composed of various administrative agencies to study and develop an action plan for addressing seismic activity in the state. The task force issued a recommended Seismic Action Plan calling for enhanced seismic monitoring and the development of a seismic response plan, and in November 2014, the Governor of Kansas announced a plan to enhance seismic monitoring in the state. In March 2015, the Kansas Corporation Commission issued its Order Reducing Saltwater Injection Rates (the "Order"). The Order identified five areas of heightened seismic concern within Harper and Sumner Counties and mandated that, within 100 days of the Order’s issuance, operators must limit saltwater injection volumes to no more than 8,000 barrels per day for any well located in one of these five areas. SandRidge and other operators of injection wells were required to reduce the injection volume, and any injection well drilled deeper than the Arbuckle Formation was required to be plugged back to a shallower formation in a manner approved by the Kansas Corporation Commission. In August 2016, the Kansas Corporation Commission issued an order that put a 16,000 barrels per day limit on additional Arbuckle disposal wells not previously identified in the Order. While no additional regulatory actions were taken in Kansas with respect to induced seismicity concerns in 2017 or 2018, 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

The EPA previously has published its findings that emissions of CO2, methane and certain other “greenhouse gases” ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emission. 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 rule could adversely affect our operations and restrict or delay its ability to obtain air
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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 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, Subpart OOOOa (“Quad Oa”). In June 2017, the EPA proposed a two-year stay of the rules and in October 2018 the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain Quad Oa requirements is technically infeasible. Regardless of the stay and potential regulatory revisions, it is possible that these rules 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 public lands that are substantially similar to the EPA Quad Oa requirements. However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. Further, in September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule. As a result of these developments, future implementation of the EPA and the BLM methane rules remains uncertain, but given the long-term trend towards increasing regulation, future federal GHG regulations for the oil and gas industry remain a possibility. Moreover, several states where we operate, including Colorado, have already adopted rules requiring operators of both new and existing sources to develop and implement a LDAR program and to install devices on certain equipment to capture 95 percent of methane emissions. Compliance with these rules could require us to purchase pollution control equipment and optical gas imaging equipment for LDAR inspections, and to hire additional personnel to assist with inspection and reporting requirements.

In addition, a number of state and regional efforts are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”). However, the Paris Agreement does not impose any binding obligations on the United States. Moreover, in June 2017, President Trump announced 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 from the Paris Agreement. Such withdrawal has not yet been finalized, and whether the United States may reenter the Paris Agreement or a separately negotiated agreement is unclear at this time. Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the Paris Agreement. The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require additional expenditures to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas we produce, and thus possibly have a material adverse effect on our revenues, as well as having the potential effect of lowering the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration 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 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. While compliance with the ESA has not had an adverse effect on our exploration, development and production operations in areas where threatened or endangered species or their habitat are known to exist, it may require us to incur increased costs to implement mitigation or protective measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. In addition, certain of our federal and state leases may contain stipulations that require us to take measures to safeguard certain species, including the sage grouse, and their habitats known to be located within the area of the lease. Although the U.S. Fish and Wildlife Service (“USFWS”) declined to list the sage grouse under the ESA in 2015 and subsequently developed a conservation plan to protect existing habit, some environmental groups have continued to raise concerns about sufficient
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protections for the sage grouse population. Under the plan, the USFWS committed to review the status of the species every five years to evaluate conservation actions, with the plan to be next reviewed and revised if necessary in 2020. In addition, the U.S. Department of Interior (“DOI”) proposed in December 2018 revisions to the existing sage grouse conservation plan that, amongst other things, was intended to give the DOI and individual states flexibility to allow for increased activity in grouse habitat management areas encompassing parts of Colorado, Idaho, Nevada, Northern California, Oregon, Utah and Wyoming. Several environmental groups have 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. For example, certain of our operations in Colorado are 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. Further, in February 2016, the USFWS published a final policy which alters how it identifies critical habitats for endangered and threatened species. In July 2018, the USFWS proposed several changes to ESA regulations, including changes to the procedures and criteria for listing or removing species from the Lists of Endangered and Threatened Wildlife and Plants and for designating critical habitat. A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. Moreover, a settlement approved by the U.S. District Court for the District of Columbia in 2011 required the USFWS to consider listing numerous species as endangered under the ESA by the end of its 2017 fiscal year; however, the agency has not yet completed this process.

The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

We are an active participant on various agency and industry committees that are developing or addressing various USFWS and other federal and state agency programs to minimize potential impacts to business activity relating to the protection of any endangered or threatened species.

Employee Health and Safety

Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA Hazard Communication Standard requires us to maintain information concerning hazardous materials used or produced in our operations and to provide this information to employees. 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 Regulation

The states in which we operate, along with some municipalities and Native American tribal areas, regulate some or all of the following activities: the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. These regulations may affect the number and location of our wells and the amounts of oil and natural gas that may be produced from our wells, and increase the costs of our operations. Moreover, obtaining or renewing permits and other approvals for operating on Native American lands can take substantial amounts of time, and could result in increased costs or delays to our operations.

Hydraulic Fracturing

Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Oil and natural gas may be recovered from certain of our oil and natural
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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 final regulations in 2012 and additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry; and in June 2016 issued final effluent limitations guidelines under the CWA that waste water from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant. The EPA also issued an Advance Notice of Proposed Rulemaking under 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.

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. At the state level, some states, including Oklahoma and Colorado, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure, operational or well construction requirements on hydraulic fracturing activities, or that prohibit hydraulic fracturing altogether. Local government 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 depths below the potable water sources. There have not been any incidents, citations or suits related to our hydraulic fracturing activities involving 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
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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 regulation 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 Texas impose financial assurance requirements on operators. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

Natural Gas Sales and Transportation

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (the “NGA”) and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of our sales of our own production. Under the Energy Policy Act of 2005 (the “EPAct 2005”), FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties of up to $1,238,271 per day for each
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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 of up to $1,116,156 per day per violation.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Currently, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the less stringent regulatory approach currently pursued by FERC and Congress might not continue indefinitely into the future. The Company is unable to determine what effect, if any, future regulatory changes might have on the Company’s natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Although its policy is still in flux, in the past FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our cost of transporting gas to point-of-sale locations.
Oil Price Controls 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 of up to $1,156,953 per day per violation. Our sales of these commodities, and any related hedging activities, are also subject to CFTC oversight as discussed above.
The price we receive from the sale of these products may be affected by the cost of transporting the products to market. Some of our transportation of oil, natural gas and NGLs is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. The FERC’s regulation of crude oil and natural gas liquids transportation rates may tend to increase the cost of transporting crude oil and natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations.

EMPLOYEES

As of December 31, 2018, the Company had 310 full-time employees, including 48 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of our 310 employees, 163 were located at the Company’s headquarters in Oklahoma City, Oklahoma at December 31, 2018, and the remaining employees worked in our various field offices and drilling sites.

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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 ability of other companies to complete and commission liquefied natural gas export facilities in the U.S.;
•U.S. and worldwide political and economic conditions;
•the level of global and U.S. inventories;
•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.
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 2014 through December 2018, the NYMEX settled price fluctuated between a high of $107.26 per Bbl and a low of $26.21 per Bbl. For natural gas, from January 2014 through December 2018, the month-end NYMEX settled price fluctuated between a high of $5.56 per MMBtu and a low of $1.71 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.

Although oil, natural gas and NGL prices rose during 2018, a buildup in inventories, lower global demand, or other factors could cause prices for U.S. oil, natural gas and NGLs to weaken, which could negatively affect our cash flows and results of operations. Under such conditions, revenues may be negatively affected, and the amount of oil, natural gas and NGLs we can produce economically may be reduced, causing us to make substantial downward adjustments to our estimated proved reserves and having a material adverse effect on our financial condition and results of operations.

Unless we replace our oil, natural gas and NGL reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
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. Declining cash flows from operations, as a result of lower commodity prices, could require us to reduce expenditures to develop and acquire additional reserves. Further, we may not be able to
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develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which could adversely affect our business, financial condition and results of operations.

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 particular project uneconomical. In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of various factors, including 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.
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.

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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, 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.

Our North Park Basin acreage may require the construction of significant gathering systems and pipelines as we increase drilling and development activity. Obtaining these services or expanding our midstream assets with acceptable commercial terms could adversely affect our ability to develop this acreage in a timely manner.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital necessary to drill such locations or construct the midstream infrastructure required to make such development profitable.
Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas 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 well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other 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.

In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Our acreage not contained within federal units must be drilled before lease expiration, generally within three to five years, 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. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, 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 current 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.

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Our development and exploration operations require substantial capital. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our oil, natural gas and NGL reserves.

The oil and natural gas industry is capital intensive. We make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of oil, natural gas and NGL reserves. Historically, we have financed capital expenditures primarily with proceeds from asset sales and from the sale of equity and debt securities and cash generated by operations. In particular, cash flow from operations was $145.5 million and $181.2 million for the years ended December 31, 2018, and 2017, respectively. Cash flow from operations was $65.6 million for the Successor 2016 Period, and cash used in operations was $112.1 million for the Predecessor 2016 Period. 

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. Similarly, failure to renew or replace our credit facility prior to its maturity on March 31, 2020 could negatively impact our liquidity. If the debt and equity capital markets are not accessible or if our ability to draw on our credit facility is compromised, 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.

Based on our 2019 capital spending plans, we estimate that our production will experience a 5%- 6% decline. This decline in production as well as other factors such as lower oil, natural gas and NGL prices, declines in reserves, or for any other reason may lead to reductions in our revenues and cash flow from operations and may limit our ability to obtain the capital necessary to sustain our operations at desired levels. In order to fund capital expenditures, we may seek additional financing.

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 lower of cost or market value of unevaluated properties. The full cost ceiling is evaluated at the end of each quarter using the SEC prices, adjusted for the impact of derivatives accounted for as cash flow hedges. The Successor Company did not incur any full cost ceiling impairment charges for the years ended December 31, 2018 or 2017. During the Successor 2016 Period, and the Predecessor 2016 Period, we incurred full cost ceiling impairment charges of $319.1 million and $657.4 million, respectively. Cumulative full cost ceiling impairment from the Emergence date through December 31, 2018 totaled $319.1 million, respectively. 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.

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

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

The ability to attract and retain key personnel is critical to the success of our business and the loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations.
The success of our business depends on key personnel, including members of senior management and technical personnel. The ability to attract and retain these key personnel may be difficult in light of the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. The market for qualified personnel has historically been, and we expect that it will continue to be, intensely competitive. We cannot assure 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.

The agreements governing our credit facility have restrictions, financial covenants and borrowing base redeterminations, which could adversely affect our operations.
The agreements governing our credit facility restrict our ability to, among other things, obtain additional financing, incur liens, enter into sale and lease back transactions, make certain investments, lease equipment, merge, dissolve, liquidate or consolidate with another entity, pay dividends or make other distributions or repurchase or redeem our stock, enter into transactions with our affiliates, create additional subsidiaries, amend or modify certain provisions of our organizational documents, enter into new transactions with our affiliates, sell assets and engage in business combinations. The credit facility also requires us to comply with certain financial covenants and ratios. See additional discussion of the credit facility under “Indebtedness—Credit Facilities.” Persistent depressed oil or natural gas prices or further decline in such prices, without other mitigating circumstances, could prevent us from complying with the financial covenants under the credit facility. Our failure to comply with any of the restrictions and covenants under the credit facility or other debt financings could result in a default under those instruments, which, if left uncured, could lead to an event of default. Such an event of default could, among other things, result in all of our existing indebtedness becoming immediately due and payable. Additionally, an event of default under one of our financing instruments could trigger cross-default provisions under our other financing instruments. The application of the remedies under the financing instruments could have a material adverse effect on our financial position.

Our credit facility limits the amounts we can borrow to a borrowing base amount. The borrowing base is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. Unscheduled redeterminations may be made at our request, but are limited to two requests per year. Borrowing base determinations are based upon proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. Outstanding borrowings exceeding the borrowing base must be repaid promptly, or we must pledge other oil and natural gas properties as additional collateral. The borrowing base is also subject to reductions upon the incurrence of junior debt, hedge terminations, dispositions of assets and casualty events which may require us to repay any deficiencies or pledge additional collateral. We may not have the financial resources in the future to make any mandatory principal prepayments under the credit facility, which are required, for example, when the committed line of credit is exceeded, proceeds of asset sales in new oil and natural gas properties are not reinvested, or indebtedness that is not permitted by the terms of the credit facility is incurred. If any future indebtedness under our credit facility were to be accelerated, our assets may not be sufficient to repay such indebtedness in full.
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It is unclear how changes in the regulation of LIBOR or the discontinuation of LIBOR all together may affect our financing costs in the future. ‎

Our credit facility bears interest based on a pricing grid tied to the London Interbank Offered Rate (“LIBOR”). On July 27, 2017, the United Kingdom’s Financial Conduct Authority (the "FCA"), which regulates LIBOR, announced that it does not intend to continue to persuade, or use its powers to compel, panel banks to submit rates for the calculation of LIBOR after 2021. It is not possible to predict whether, and to what extent, panel banks will continue to provide LIBOR submissions to the administrator of LIBOR after this time, which may cause LIBOR to perform differently than it did in the past and have other consequences which cannot be predicted.

In addition, any other legal or regulatory changes made by the FCA, ICE Benchmark Administration Limited, the European Money Markets Institute (formerly Euribor-EBF), the European Commission or any other successor governance or oversight body, or future changes adopted by such body, in the method by which LIBOR is determined or the transition from LIBOR to a successor benchmark may result in, among other things, a sudden or prolonged increase or decrease in LIBOR, a delay in the publication of LIBOR, and changes in the rules or methodologies in LIBOR, which may discourage market participants from continuing to administer or to participate in LIBOR’s determination. This could result in LIBOR no longer being determined and published. If a published U.S. dollar LIBOR rate is unavailable after 2021, the interest rate on our credit facility will need to be determined using alternative methods, which may result in interest obligations which are more than or do not otherwise correlate over time with the payments that would have been made on any outstanding debt under the facility if U.S. dollar LIBOR was available in its current form. Further, the same costs and risks that may lead to the discontinuation or unavailability of U.S. dollar LIBOR may make one or more alternative methods of calculating interest impossible or impracticable to determine. As a result, any of these consequences may have an adverse effect on our financing costs. ‎

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 accuracy of our reserve estimates;
•the actual cost of development and production expenditures;
•the amount and timing of actual production;
•supply of and demand for oil, natural gas and NGLs; and
•changes in governmental regulation or taxation.
The timing of both our production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, we use a 10% discount factor when calculating discounted future net cash flows, which may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

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 2018, we completed a total of 29 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;
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•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 experienced drought conditions. 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.
During and following the 2008 global financial crisis, financial and capital markets were volatile due to multiple factors, including significant losses in the financial services sector and uncertain and rapidly changing economic conditions both in the U.S. and globally. In some cases, financial markets produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial and/or operating strength. Volatility in the capital markets can significantly increase the cost of raising money in the debt and equity capital markets. Future market volatility, generally, and persistent weakness in commodity prices may adversely affect our ability to access capital and credit markets or to obtain funds at low interest rates or on other advantageous terms. These factors may adversely affect our business, results of operations or liquidity.

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

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

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate.
As of December 31, 2018, approximately 42.4% of our total reserves were proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Therefore, recoveries from these fields may not match current expectations. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves.

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.
As of December 31, 2018, approximately 69.2% of our proved reserves and approximately 88.6% of our annual production was located in the Mid-Continent. This concentration could disproportionately expose us to operational and regulatory risk in these areas. This relative 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
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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 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 results of our drilling operations.
A significant aspect of our exploration and development plan involves seismic data. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are present in those structures. Other geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than our professionals. Our drilling activities may not be geologically successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area may not improve as a result of using 2-D and 3-D seismic data.

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

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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, 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 production 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.

New laws or regulations, or changes to existing laws or regulations, may unfavorably impact us, could result in increased operating costs and could have a material adverse effect on our financial condition and results of operations. In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules promulgated thereunder could reduce trading positions in the energy futures or swaps markets and materially reduce hedging opportunities for us, which could adversely affect our revenues and cash flows during periods of low commodity prices, and which could adversely affect our ability to restructure hedges when it might be desirable to do so.

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.


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Risks and uncertainties related to the adoption and implementation of regulations restricting oil and gas development in Colorado.

We have substantial undeveloped reserves and unproved acreage in the North Park Basin area of Jackson County, Colorado. Recently, various initiatives have been promoted by interest groups in Colorado to increase regulations restricting oil and gas development. For example, on November 6, 2018, Coloradans considered Proposition 112, a ballot initiative that would have established a new statewide minimum distance requirement for new oil and gas development far in excess of existing Colorado Oil and Gas Conservation Commission (“COGCC”) setback regulations. Although Coloradans did not approve Proposition 112, future similar initiatives, if implemented, could pose operational challenges, substantially limit our development activity and require higher levels of capital expenditures than we currently anticipate, and therefore have a significant adverse effect on our ability to develop proved undeveloped reserves in the North Park Basin. Such restrictions, additional costs and delays could adversely impact our financial condition, results of operations and/or cash flows.
Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, or the FTC, 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 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. 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 utilize hydraulic fracturing techniques in the majority of our drilling and completion programs. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAA final regulations in 2012 and
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additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry; and in June 2016 issued final effluent limitations guidelines under the CWA that waste-water from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant. The EPA also issued an Advance Notice of Proposed Rulemaking under TSCA in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing, but, to date, has taken no further action. Separately, the BLM published a final rule in March 2015 that establishes 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. 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.

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. 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. Restrictions on hydraulic fracturing could also reduce the amount of oil, natural gas or NGLs that are ultimately produced in commercial quantities from our properties.

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

Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed. The adoption of any new laws, regulations, or directives that restrict our ability to dispose of saltwater generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or otherwise, or by requiring us to shut down disposal wells, which could negatively affect the economic lives of our properties.

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

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
The EPA previously published its findings that emissions of GHGs present a danger to public health and the environment because such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted various rules to address GHG emissions under existing provisions of the CAA. For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis, which includes certain of our operations. In addition, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of an LDAR program to minimize methane emissions, under the CAA’s New Source Performance Standards Quad Oa. However, over the past year the EPA has taken several steps to delay implementation of the Quad Oa standards, and the agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and in October 2018, the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain Quad Oa requirements is technically infeasible. Regardless of the stay and potential regulatory revisions, it is possible that these rules will continue to require oil and gas
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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. 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 where we operate, including Colorado, have already adopted rules requiring operators of both new and existing sources to develop and implement LDAR program and install devices on certain equipment to capture 95% of methane emissions.

Compliance with these rules could require us to purchase pollution control equipment, optical gas imaging equipment for LDAR inspections, and to hire additional personnel to assist with inspection and reporting requirements.

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, in June 2017, President Trump stated 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 from the Paris Agreement. Such withdrawal has not yet been finalized, and whether the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time. Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the international climate change agreement.

The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur additional costs to monitor, report and potentially reduce emissions of GHGs associated with its 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 exploration 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.

Risks and uncertainties related to the potential sale or lease of our corporate headquarters.
Our corporate headquarters building in downtown Oklahoma City, OK, is substantially underutilized. We have entered into a brokerage agreement to seek to lease the unutilized portion of the building. We may seek and/or receive offers to purchase the entire building in the future. Any alternative we pursue is subject to certain risks and uncertainties, including, among other things, the possibility that any alternative we select will not be completed on terms that are advantageous to us and the likelihood that an outright sale of our corporate headquarters will be at a sales price significantly below its current carrying value on our books.

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
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an attack. 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.

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, 2018, 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 material weaknesses in our controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation, including those related to acquired businesses, or other effective improvement of our internal controls could harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation which could adversely affect our ability to hedge risks associated with our business.
We may enter into financial derivative instruments with respect to a portion of our production to manage our exposure to oil, gas, and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves 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 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 Act created a new regulatory framework for oversight of derivatives transactions by the CFTC and the SEC. Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility, unless the “end-user” exception from clearing applies. The Dodd-Frank Act also established a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets and also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into for bona fide hedging purposes).

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

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

The future of the CFTC's rulemaking remains uncertain under the current presidential administration. Recent rule proposals by the CFTC suggest that final consideration of major proposed rules will be made by the current administration. During the last quarter of 2016, the CFTC decided to re-propose, rather than finalize, certain regulations, including (a) limitations on speculative futures and swap positions, (b) regulations on automated trading algorithms and (c) limitations on swap capital requirements for swap dealers and major swap participants. It is also uncertain whether the current Chairman of the CFTC and other CFTC staff will remain with the CFTC under the current presidential administration. If finalized, the position limits rule may have an impact on our ability to hedge our exposure to certain enumerated commodities.

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

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

We have programs, processes and technologies in place to attempt to prevent, detect, contain, respond to and mitigate security-related threats and potential incidents. We undertake ongoing improvements to our systems, connected devices and information-sharing products in order to minimize vulnerabilities, in accordance with industry and regulatory standards; however, because the techniques used to obtain unauthorized access change frequently and can be difficult to detect and 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.

Risks Relating to Our Emergence from Bankruptcy
Our historical financial information may not be indicative of future financial performance.
Our capital structure was significantly impacted by the Plan. Under fresh-start reporting rules that applied to us upon the Emergence Date, assets and liabilities were adjusted to fair values and our accumulated deficit was restated to zero. Accordingly, because fresh-start reporting rules applied, our financial condition and results of operations following emergence from Chapter 11 will not be comparable to the financial condition and results of operations reflected in our historical financial statements.


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Risks Relating to our Common Stock

The exercise of all or any number of outstanding Warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.
As of the date of filing this report, we have outstanding Warrants to purchase approximately 6.6 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, 3.0 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.

Item 1B. Unresolved Staff Comments

None.

Item 2.  Properties

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

Item 3.  Legal Proceedings

As previously disclosed, on May 16, 2016, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016.

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
•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
•Barton W. Gernandt Jr., et al. v. SandRidge Energy, Inc., Case No. 5:15-cv-00834-D, USDC, Western District of Oklahoma

On November 8, 2018, the court in the Gernandt case granted the defendants’ respective motions to dismiss and dismissed the action with prejudice.

Although the remaining two Cases have not been dismissed against certain former officers and directors who remain defendants in the Cases, the Company remains as a nominal defendant in each of the Cases so that any of the respective plaintiffs may seek to recover proceeds from any applicable insurance policies or proceeds. In each of the Cases, to the extent liability exceeds the amount of available insurance proceeds, the Company may owe indemnity obligations to its former officers and/or directors who remain as defendants in such action. An estimate of reasonably probable losses associated with any of the Cases cannot be made at this time, however the Company believes that any potential liability with respect to the Cases will not be material. The Company has not established any reserves relating to any of the Cases.

In addition to the matters 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. Pursuant to the terms of the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II, the Company is obligated to indemnify, for as long as the Trusts exist, each Royalty Trust against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters as stipulated in the respective agreements with each Royalty Trust.

Item 4.  Mine Safety Disclosures

Not applicable.
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PART II

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

PRICE RANGE OF COMMON STOCK

Since October 4, 2016, the Successor Company’s common stock has been listed on the New York Stock Exchange (“NYSE”) under the symbol “SD.” During the period from January 7, 2016 through October 3, 2016, our common stock was quoted for public trading on the Pink Sheets quotations system, an over-the-counter market, under the symbol “SDOCQ.PK.” The over-the-counter market quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions. Prior to January 7, 2016, the Predecessor Company’s common stock was also listed on the NYSE under the symbol “SD.” 

On February 20, 2019, there were 312 record holders of the Company’s common stock.

We have neither declared nor paid any cash dividends on either the Predecessor or the Successor Company’s respective common stock, and we do not anticipate declaring any dividends in the foreseeable future. We expect to retain cash for the operation and expansion 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. If our dividend policy changes in the future, our ability to pay dividends would be subject to these restrictions and 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.

PERFORMANCE GRAPH

The following graph compares the cumulative total return to stockholders on SandRidge common stock relative to the cumulative total returns of the S&P Oil and Gas Exploration and Production Index and the S&P 500 Index from October 4, 2016 through December 31, 2018. The graph assumes that the value of the investment in the Successor Company’s common stock and in each of the indexes was $100.00 on October 4, 2016, the date the Successor Company’s common stock began
trading.
wfx-20181231_g1.jpg

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The following graph compares the cumulative total return to stockholders on SandRidge common stock relative to the cumulative total returns of the S&P Oil and Gas Exploration and Production Index and the S&P 500 Index from January 1, 2014 through October 3, 2016. The graph assumes that the value of the investment in the Predecessor Company’s common stock and in each of the indexes was $100.00 on January 1, 2014.
wfx-20181231_g2.jpg

The performance graphs above are furnished and not filed for purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any registration statement filed under the Securities Act unless specifically identified therein as being incorporated therein by reference. The performance graphs are not soliciting material subject to Regulation 14A.
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ISSUER PURCHASES OF EQUITY SECURITIES

The following table presents a summary of share repurchases made during the three-month period ended December 31, 2018.
Total Number of Shares Purchased(1)
Average Price
Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced ProgramMaximum  Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program
(In millions)
Period
October 1, 2018 - October 31, 2018— $— N/A N/A 
November 1, 2018 - November 30, 2018578 $9.76 N/AN/A 
December 1, 2018 - December 31, 20184,379 $8.80 N/AN/A 
Total
4,957 — 
____________________
1. Includes shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards.


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Item 6.  Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, our selected financial information, which is derived from our audited consolidated financial statements for the respective periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and our consolidated financial statements and notes thereto contained in “Financial Statements and Supplementary Data” in Item 8 of this report. The following information is not necessarily indicative of future results.
SuccessorPredecessor
 Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,Year Ended December 31,
 201820172016201620152014
Statement of Operations Data
 (in thousands, except per share data)
Revenues$349,395 $357,299 $98,456 $293,809 $768,709 $1,558,758 
Total operating expenses(1)359,770 317,668 434,801 1,200,012 5,411,387 968,534 
(Loss) income from operations(10,375)39,631 (336,345)(906,203)(4,642,678)590,224 
Other (expense) income
Interest expense(2,787)(3,868)(372)(126,099)(321,421)(244,109)
Gain on extinguishment of debt1,151 — — 41,179 641,131 — 
Gain on reorganization items, net— — — 2,430,599 — — 
Other income, net2,865 2,550 2,744 1,332 2,040 3,490 
Total other income (expense)1,229 (1,318)2,372 2,347,011 321,750 (240,619)
(Loss) income before income taxes(9,146)38,313 (333,973)1,440,808 (4,320,928)349,605 
Income tax (benefit) expense(71)(8,749)9 11 123 (2,293)
Net (loss) income(9,075)47,062 (333,982)1,440,797 (4,321,051)351,898 
Less: net (loss) income attributable to noncontrolling interest(2)
— — — — (623,506)98,613 
Net (loss) income attributable to SandRidge Energy, Inc.
(9,075)47,062 (333,982)1,440,797 (3,697,545)253,285 
Preferred stock dividends— — — 16,321 37,950 50,025 
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders
$(9,075)$47,062 $(333,982)$1,424,476 $(3,735,495)$203,260 
(Loss) earnings per share
Basic$(0.26)$1.45 $(17.61)$2.01 $(7.16)$0.42 
Diluted$(0.26)$1.44 $(17.61)$2.01 $(7.16)$0.42 
____________________
1.Includes full cost ceiling limitation impairments of $319.1 million, $657.4 million, $4.5 billion and $164.8 million for the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2015 and 2014, respectively. No full cost ceiling limitation impairments were recorded for the years ended December 31, 2018 and 2017.
2.Information presented for the years ended December 31, 2014 and 2015, includes 100% of the interests and activities of the Royalty Trusts, including amounts attributable to noncontrolling interest. On January 1, 2016, we adopted the provisions of ASU 2015-02, “Amendments to the Consolidation Analysis,” which led to the conclusion that the Royalty Trusts were no longer variable interest entities, and a cumulative-effect adjustment was made to equity to remove the effect of any previously recorded noncontrolling interest. Prior periods were not restated. For the 2016, 2017, and 2018 periods, we have proportionately consolidated only our share of each Royalty Trust.



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SuccessorPredecessor
 As of December 31,As of December 31,
 20182017201620152014
Balance Sheet Data (in thousands)
Cash and cash equivalents$17,660 $99,143 $121,231 $435,588 $181,253 
Property, plant and equipment, net$949,949 $923,240 $817,932 $2,234,702 $6,215,057 
Total assets(1)$1,024,338 $1,119,627 $1,081,392 $2,922,027 $7,211,823 
Total debt(1)$— $37,502 $305,308 $3,562,378 $3,148,034 
Total stockholders’ equity (deficit)$847,721 $839,940 $512,917 $(1,187,733)$3,209,820 
Total liabilities and stockholders’ equity (deficit)$1,024,338 $1,119,627 $1,081,392 $2,922,027 $7,211,823 
____________________
1.Reflects the reclassification of certain debt issuance costs from other assets to long-term debt of $69.1 million and $47.4 million for the years ended December 31, 2015, and 2014, respectively, as a result of the retrospective adoption of ASU 2015-03 on January 1, 2016.
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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1, “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.

Overview

We are an oil and natural gas company with a principal focus on exploration and production activities in the U.S. Mid-Continent and North Park Basin of Colorado.

Basis of Presentation

We emerged from Chapter 11 and applied fresh start accounting in October 2016; however, this reorganization did not require the divestiture of any of our oil and natural gas properties. As a result, certain operating results 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 certain of the combined operating results of the Predecessor 2016 Period and the Successor 2016 Period during the year ended December 31, 2016, are still comparable with certain operating results in the other years presented. Accordingly, we believe that discussing the combined results of operations and cash flows of 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 analysis to supplement the discussion.

Operational Activities

Operational activities for the years ended December 31, 2018, and 2017 include the following:
Year Ended December 31,  
20182017
Gross Wells Drilled(2) Net Wells Drilled(2) 
Average Rigs Drilling
Gross Wells Drilled(2) Net Wells Drilled(2) 
Average Rigs Drilling
Area
Mid-Continent (1)
22 8.0 1.7 20 14.1 2.3 
North Park Basin
14 14.0 0.7 7 7.0 0.6 
Total
36 22.0 2.4 27 21.1 2.9 
____________________
1.During the years ended December 31, 2018 and 2017, we drilled 15 and three wells, respectively, under the drilling participation agreement. Under this agreement, we are receiving a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells. The Counterparty to the drilling participation agreement has been billed costs totaling $65.2 million for drilling and completion activity from inception through December 31, 2018, under the initial $100.0 million tranche of the agreement.
2.Includes wells with a rig release date during the years ended December 31, 2018 or 2017, respectively.

Total production for 2018 was comprised of approximately 28.2% oil, 48.9% natural gas and 22.9% NGLs compared to 27.9% oil, 49.5% natural gas and 22.6% NGLs in 2017.

Recent Events

•On January 28, 2019, the Board appointed Paul D. McKinney as President and Chief Executive Officer, effective January 29, 2019. Mr. McKinney succeeds Mr. William M. Griffin, Jr., who continues to serve on the Board.
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•On November 2, 2018, we acquired certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas as discussed further in "—Acquisitions and Divestitures" below.

•On November 1, 2018, we sold substantially all of our oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, together with 13,125,000 common units of the Trust as discussed further in "—Acquisitions and Divestitures" below.

•During the second half of 2018, the Board reviewed our strategic options which could have included a possible sale of the Company or certain significant assets, and conducted a complete and thorough review of our assets and operating strategies, including capital expenditures and drilling programs, and overall cost structure. On September 10, 2018, the Board announced it had concluded the formal strategic review process following the thorough evaluation of multiple potential transactions, all of which the Board believed significantly undervalued either the Company or its resources.
•As a result of the proxy contest discussed further in "Note 18 - Proxy Contest", the size of the Board was expanded to eight directors in June 2018. The Board now consists of previous directors Sylvia K. Barnes, David J. Kornder and William M. Griffin, Jr., and newly elected members Bob G. Alexander, Jonathan Christodoro, Jonathan Frates, John J. "Jack" Lipinski and Randolph C. Read. 

Outlook

After completing the strategic review process noted above, the Board concluded that our future course is to develop our inventory of NW STACK and North Park Basin drilling opportunities and pursue value enhancing opportunities in the Mid-Continent. We will also pursue accretive acquisitions of strategic assets that provide high quality production and development upside. Focusing on cost reductions, margin improvements and opportunistic divestment of core and non-core properties will also be a part of our plan moving forward. Based on these strategic objectives, we intend to spend between $160.0 million and $180.0 million in our 2019 capital budget plan. The substantial majority of these budgeted expenditures is designated for drilling and completion activities. Based on our 2019 capital spending plans, we estimate that our production will experience a 5%- 6% decline. We will continue to monitor the changing market conditions and the results of our operations and will take measures to help achieve our strategic objectives, enhance shareholder value and improve our competitiveness in the marketplace. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.

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, our ability to find and economically develop and produce our reserves, and changes in the fair value of our commodity derivative contracts. 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,
20182017201620152014
Oil (per Bbl)$64.90 $50.85 $43.47 $48.75 $92.91 
Natural gas (per Mcf)$3.07 $3.02 $2.55 $2.62 $4.26 

In order to reduce our exposure to price fluctuations, we have historically entered into commodity derivative contracts for a portion of our anticipated future oil and natural gas production as discussed in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.” Reducing the Company’s exposure to price volatility helps mitigate the risk that we will not have adequate funds available for our capital expenditure programs. During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oil and natural gas. Conversely, during periods of declining market prices of oil and natural gas, 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. At December 31, 2018, we have no oil derivative contracts in place and have natural gas derivatives in place through March of 2019.


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Acquisitions and Divestitures of Oil and Gas Properties

Divestiture of Permian Basin Properties. On November 1, 2018, we sold substantially all of our oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with all of our 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced our asset retirement obligations by approximately $26.9 million. The CBP assets and interest in the Permian Trust include 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with our CBP operations. As a result of this divestiture, we no longer have any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between our capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale.

Acquisition of Oil and Natural Gas Interests. On November 2, 2018, we acquired certain interests in oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million. The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which we operate, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in our saltwater gathering and disposal system in the Mississippian Lime. This acquisition is expected to increase total production for existing producing properties by approximately 10%.

Acquisition of NW STACK Properties. On February 10, 2017, 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.

2017 Oil and Natural Gas Property Divestitures. In 2017, we divested various non-core oil and natural gas properties for approximately $17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.

Divestiture of WTO Properties and Release from Treating Agreement. In January 2016, we paid $11.0 million in cash and transferred ownership of substantially all of our oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental and were released from all past, current and future claims and obligations under an existing 30-year treating agreement with Occidental. In connection with this transfer, the Predecessor Company recognized a loss of approximately $89.1 million on the termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field and reduced its asset retirement obligations associated with its oil and natural gas properties by $34.1 million.



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Oil, Natural Gas and NGL Production and Pricing

The table below presents production and pricing information for the years ended December 31, 2018, and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined results for the full year ended December 31, 2016.
SuccessorPredecessorCombined

Year Ended December 31,

Year Ended December 31,
Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,

Year Ended December 31,
20182017201620162016
Production data (in thousands)
Oil (MBbls)3,477 4,157 1,214 4,315 5,529 
NGL (MBbls)2,829 3,376 999 3,358 4,357 
Natural gas (MMcf)36,175 44,237 12,771 44,124 56,895 
Total volumes (MBoe)12,335 14,906 4,342 15,027 19,369 
Average daily total volumes (MBoe/d)33.8 40.8 47.7 54.6 52.9 
Average prices—as reported(1)
Oil (per Bbl)$61.73 $48.72 $47.03 $36.85 $39.09 
NGL (per Bbl)$23.72 $18.16 $14.77 $12.67 $13.15 
Natural gas (per Mcf)$1.85 $2.09 $2.07 $1.78 $1.84 
Total (per Boe)$28.27 $23.90 $22.64 $18.63 $19.53 
Average prices—including impact of derivative contract settlements(2)
Oil (per Bbl)$51.35 $49.75 $54.59 $51.05 $51.83 
NGL (per Bbl)$23.72 $18.16 $14.77 $12.67 $13.15 
Natural gas (per Mcf)$1.89 $2.15 $1.96 $1.77 $1.81 
Total (per Boe)$25.47 $24.38 $24.41 $22.70 $23.08 
____________________
1.Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.
2.Excludes settlements of commodity derivative contracts prior to their contractual maturity, if any.

For a discussion of reserves, PV-10 and reconciliation to Standardized Measure, see “Business— Primary Operations—Proved Reserves” in Item 1 of this report.

The table below presents production by area of operation for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period, and illustrates the impact of (i) natural declines in existing producing wells in the Mid-Continent, (ii) the Permian Divestiture in November 2018 and drilling no new wells in the Permian and other regions during 2018, 2017 and 2016, and (ii) continued development of the North Park Basin properties, which were acquired in December 2015 and the NW STACK, which was acquired in February 2017.
SuccessorPredecessor
Year Ended December 31,Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,
2018201720162016
Production (MBoe) % of Total Production Production (MBoe) % of Total Production Production (MBoe) % of Total Production Production (MBoe) % of Total Production 
Mississippian Lime10,003 81.1 %12,838 86.2 %4,018 92.5 %14,119 94.0 %
NW STACK925 7.5 %882 5.9 %— — %— — %
North Park Basin1,034 8.4 %673 4.5 %180 4.1 %320 2.1 %
Permian Basin373 3.0 %513 3.4 %144 3.4 %489 3.3 %
Other— — %— — %— — %99 0.6 %
Total
12,335 100.0 %14,906 100.0 %4,342 100.0 %15,027 100.0 %
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Revenues

Consolidated revenues for the years ended December 31, 2018, and 2017, the Successor 2016 Period, the Predecessor 2016 Period, and the combined results for the year ended December 31, 2016 are presented in the table below (in thousands).
SuccessorPredecessorCombined
 Year Ended December 31,Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,

Year Ended December 31,
 20182017201620162016
Revenues
Oil$214,651 $202,539 $57,093 $159,023 $216,116 
NGL67,111 61,322 14,756 42,541 57,297 
Natural gas66,964 92,349 26,458 78,407 104,865 
Other669 1,089 149 13,838 13,987 
Total revenues$349,395 $357,299 $98,456 $293,809 $392,265 

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, 2018 and 2017 are shown in the table below (in thousands):
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 201768,005 
2017 oil, natural gas and NGL revenues

356,210 
Change due to production volumes in 2018(59,897)
Change due to average prices in 201852,413 
2018 oil, natural gas and NGL revenues $348,726 

Oil, natural gas and NGL revenues decreased by a combined $7.5 million, or 2.1% for the year ended December 31, 2018, compared to 2017 due largely to a 2.6 MMBoe decrease in total production, primarily resulting from natural declines in existing producing wells and a decline in prices received for our natural gas production. This decrease was partially offset by an increase in average prices received for our oil and NGL production.

Oil, natural gas and NGL sales decreased by a combined $22.1 million, or 5.8% for the year ended December 31, 2017, compared to 2016 due largely to a 4.5 MMBoe decrease in total production, primarily resulting from 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 in “—Expenses” below, whereas the combined 2016 period only includes the impact of this election for the Successor 2016 Period.

Other revenues primarily include drilling and oilfield services and marketing and midstream sales, which decreased in 2017 compared to 2016 largely due to discontinuing all remaining drilling and oilfield services operations in 2016, and transferring substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental in January 2016.


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Expenses

Consolidated expenses for the years ended December 31, 2018, and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined results for the year ended December 31, 2016 are presented below.
SuccessorPredecessorCombined
 Year Ended December 31,Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,Year Ended December 31,
 20182017201620162016
 (In thousands)
Expenses
Production$92,703 $102,728 24,997 129,608 $154,605 
Production taxes19,470 13,644 2,643 6,107 8,750 
Depreciation and depletion—oil and natural gas127,281 118,035 36,061 90,978 127,039 
Depreciation and amortization—other11,982 13,852 3,922 21,323 25,245 
Impairment4,170 4,019 319,087 718,194 1,037,281 
General and administrative41,666 76,024 9,837 116,091 125,928 
Accelerated vesting of employment compensation6,545 — — — — 
Proxy contest7,139 — — — — 
Terminated merger costs— 8,162 — — — 
Employee termination benefits32,657 4,815 12,334 18,356 30,690 
Loss (gain) on derivative contracts17,155 (24,090)25,652 4,823 30,475 
Loss on settlement of contract— — — 90,184 90,184 
Other operating expense(998)479 268 4,348 4,616 
Total expenses$359,770 $317,668 $434,801 $1,200,012 $1,634,813 

Production expense includes but is not limited to, lease operating expense and ad valorem taxes on our oil and gas properties. Production expenses for 2018 decreased $10.0 million, or 9.8% from 2017. Production costs per Boe increased to $7.52 per Boe for the 2018 period from $6.89 per Boe in 2017, primarily due to the decrease in total production noted above.
 
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, primarily due to (i) the Successor Company’s presentation of transportation costs totaling $29.1 million as a reduction from revenues for the year ended December 31, 2017, compared to the presentation of only $7.4 million of transportation costs as 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 taxes, which are levied by the state governments in the areas in which we operate, typically change in direct correlation with increases or decreases in our oil, natural gas and NGL revenues. However, production taxes as a percentage of oil, natural gas and NGL revenue increased to approximately 5.6% in 2018, compared to 3.8% for 2017, and 2.3% for 2016. These increases were primarily due to fewer wells having the benefit of tax credits in 2018 and 2017 compared to 2016 due to the loss of certain horizontal tax credits, which caused previous rates to increase back to statutory rates for certain wells.

Depreciation and depletion for oil and natural gas properties increased by $9.2 million for the year ended December 31, 2018 compared to 2017 due to an increase in the average depreciation and depletion rate to $10.32 per Boe in 2018 compared to an average rate of $7.92 in 2017. The increase in the rate primarily resulted from continuing to incur higher actual drilling and completion costs per Boe during 2018 compared to the lower rates experienced in 2017 which resulted from the significant ceiling test write-down in the fourth quarter of 2016. Additionally, more capital is being allocated to develop our North Park Basin oil asset where future development costs are higher. As a result, average depletion rates have increased and may continue to increase as we develop this area.

Depreciation and depletion for oil and natural gas properties decreased by $9.0 million for the year ended December 31, 2017 compared to the combined 2016 periods, primarily due to the decrease in production. This decrease was partially
53

offset by an increase in the average depreciation and depletion rate to $7.92 per Boe in 2017 compared to an average rate of $6.56 per Boe for the combined 2016 periods. This increase in the average rate primarily resulted from (i) incurring higher actual drilling and completion costs per Boe during the 2017 period compared to the rate per Boe calculated at December 31, 2016 following the significant ceiling test write-down incurred in the fourth quarter of 2016, (ii) a shift of more capital to develop our North Park Basin oil asset where the anticipated future development costs are likewise expected to be higher than the 2016 rate, and (iii) a $3.1 million increase in accretion for the year ended December 31, 2017, compared to the combined 2016 periods, primarily due to the Successor Company recording a higher fresh start valuation for asset retirement obligations on the Emergence Date.

Depreciation and depletion for oil and natural gas properties for the Successor 2016 Period was recorded at an average depreciation and depletion rate of $8.31 per Boe compared to a rate of $6.05 per Boe for the Predecessor 2016 Period, which reflects an increase in reserve values due to fresh start valuation adjustments recorded for reserves as of October 1, 2016, and the full cost ceiling impairments recorded in the Successor 2016 Period.

Depreciation and amortization for non-oil and gas properties decreased across all periods primarily due to (i) the sale of substantially all drilling assets during 2016 and 2015 after discontinuing drilling operations, (ii) the sale of a property located in downtown Oklahoma City, Oklahoma as well as other corporate assets, and (iii) the divestiture of the WTO properties and related assets.

Impairment expense for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016 consisted of the following (in thousands):

SuccessorPredecessorCombined
 Year Ended December 31,Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,Year Ended December 31,
 20182017201620162016
Impairment
Full cost pool ceiling limitation$— $— $319,087 $657,392 $976,479 
Drilling assets22 4,019 — 3,511 3,511 
Electrical infrastructure assets— — — 55,600 55,600 
Midstream assets4,148 — — 1,691 1,691 
Total impairment$4,170 $4,019 $319,087 $718,194 $1,037,281 

Full cost pool impairment. Upon the application of fresh start accounting, the value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the SEC prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment of $319.1 million.

Full cost pool impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairments recorded in 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 through 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 had been developed with three or more horizontal wells per section as inter-well pressure communication had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in our Mississippian wells producing with artificial lift resulted in increased production decline rates that became more predictable on a large group of base wells as this population of wells had been producing for more than two years.

Drilling asset impairment. Impairment in 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value. Impairments were also recorded on certain drilling assets during the Predecessor 2016 Period, upon determining their future use was limited after discontinuing all remaining drilling operations in 2016.

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Electrical infrastructure asset impairment. Impairment in the Predecessor 2016 Period primarily reflects a write-down of the value of our electrical transmission system due to a decrease in projected Mid-Continent production volumes supporting the system’s usage.

Midstream asset impairment. Impairment recorded on midstream assets in 2018 primarily reflects the write-down of midstream generator assets classified as held for sale to estimated net realizable value. Impairment recorded on midstream assets in 2016 resulted primarily from the write-down of generators, compressors and various other equipment due to their limited use.

General and administrative expenses decreased $34.4 million, or 45.2%, for the year ended December 31, 2018 compared to 2017 due primarily to (i) a decrease of $26.4 million in compensation related costs largely resulting from a reduction in force during the first quarter of 2018 as well as additional declines in headcount throughout 2018, (ii) a decrease of $6.0 million in professional services costs due primarily to incurring significant consultant fees in the 2017 period after our restructuring, and (iii) a net decrease of $2.0 million in other miscellaneous general and administrative items.

General and administrative expenses decreased $49.9 million, or 39.6%, for the year ended December 31, 2017 compared to 2016 due primarily to (i) a decrease of $25.0 million in professional services costs due to incurring significant consultant and legal fees in the 2016 period in contemplation of our restructuring, and (ii) a $23.6 million decrease in net salary costs largely resulting from reductions in force during the first and fourth quarters of 2016. The remaining change is due to the net effect of significant reductions in director and officer insurance costs, bad debt expense, and costs largely related to the reduction in headcount during 2016, offset partially by increases in other miscellaneous general and administrative items.

Accelerated vesting of employment compensation costs incurred during the year ended December 31, 2018 include compensation costs recognized for the accelerated vesting of certain share and incentive-based awards granted to our employees and directors related to the change in the composition of the Board resulting from the 2018 annual meeting as discussed in "Note 18 - Proxy Contest" to the consolidated financial statements in Item 8 of this report.

Proxy contest costs for the year ended December 31, 2018 include legal, consulting and advisory fees incurred in the proxy contest which were initiated in response to shareholder actions in 2018. See "Note 18 - Proxy Contest" to the consolidated financial statements in Item 8 of this report for additional discussion of this matter.

Terminated merger costs include legal and professional costs incurred from the aborted proposed merger of SandRidge with Bonanza Creek, as well as certain costs incurred to address shareholder claims and fees paid to Bonanza Creek for termination of the proposed merger in December 2017. 
 
Employee termination benefits for the year ended December 31, 2018, include cash and share-based severance costs incurred primarily as a result of (i) the reduction in force in the first quarter of 2018 and (ii) severance costs associated with the departure of our former CEO, James Bennett, former CFO, Julian Bott, and other senior officers.
 
Employee termination benefits for the year ended December 31, 2017, primarily include cash and share-based severance costs incurred upon the departure of our former Executive Vice President of Investor Relations and Strategy, Duane Grubert.

Employee termination benefits for the year ended December 31, 2016, include cash and share-based severance costs incurred primarily as a result of (i) reductions in force in the first and fourth quarters of 2016, (ii) severance costs associated with the departure 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 operations in the first quarter of 2016.

See "Note 19 - Employee Termination Benefits" to the consolidated financial statements in Item 8 of this report for additional information.
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We recorded net loss (gain) on commodity derivative contracts of $17.2 million and $(24.1) million for the years ended December 31, 2018, and 2017, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments (receipts) upon settlement of $35.3 million and $(7.3) million, respectively. Approximately $0.8 million of the payments made in 2018 relate to early settlements due to unwinding all outstanding oil derivative contracts in December 2018.

As previously noted, on November 14, 2017, we entered into an Agreement and Plan of Merger with Bonanza Creek. In contemplation of the proposed merger, which would have been partially financed with debt, we entered into several oil derivative contracts in November 2017. Approximately $8.0 million of the total 2018 loss reported above related to net cash payments upon settlement for these oil derivatives. Approximately $4.9 million in losses were included in the net gain reported above related to these oil derivatives for the year ended December 31, 2017.

We recorded losses on commodity derivative contracts of $25.7 million and $4.8 million for the Successor 2016 Period and the Predecessor 2016 Period, respectively, as reflected in the accompanying consolidated statements of operations included in Item 8 of this report, which include net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. Approximately $17.9 million of the net cash receipts for the Predecessor 2016 Period related to early settlements of commodity derivative contracts in the second quarter of 2016, primarily in response to the Chapter 11 Petitions being filed.

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 quarter as a component of operating expenses. Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural gas production to determine “effective prices.” In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts, and cash is paid on settlement of contracts due to higher oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts. See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” of this report for additional discussion of our commodity derivatives.

Loss on settlement of contract in the Predecessor 2016 Period consists of a $78.9 million loss resulting from the termination of a gas treating and CO2 delivery agreement with Occidental, and a loss of $11.2 million recorded for the cease-use of transportation agreements that supported production from the Piñon field.

Other Income (Expense)

Other income (expense) for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016, is reflected in the table below (in thousands):
 SuccessorPredecessorCombined
 Year Ended December 31,Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,

Year Ended December 31,
20182017201620162016
Other (expense) income
Interest expense, net$(2,787)$(3,868)$(372)(126,099)$(126,471)
Gain on extinguishment of debt1,151 — — 41,179 41,179 
Gain on reorganization items, net— — — 2,430,599 2,430,599 
Other income, net2,865 2,550 2,744 1,332 4,076 
Total other income (expense)$1,229 (1,318)$2,372 $2,347,011 $2,349,383 


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Interest expense for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016 consisted of the following (in thousands):
SuccessorPredecessorCombined

Year Ended December 31,

Year Ended December 31,
Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,

Year Ended December 31,
20182017201620162016
Interest expense
Interest expense on debt$2,747 $4,786 $1,590 $123,350 $124,940 
Amortization of debt issuance costs, premium and discounts
423 100 (81)7,730 7,649 
Gain on long-term debt derivatives— — — (1,324)(1,324)
Capitalized interest(22)— — (2,240)(2,240)
Total 3,148 4,886 1,509 127,516 129,025 
Less: interest income(361)(1,018)(1,137)(1,417)(2,554)
Total interest expense, net$2,787 $3,868 $372 $126,099 $126,471 

Interest expense incurred during the years ended December 31, 2018 and 2017, is primarily comprised of interest recorded on the Building Note and commitment fees on the undrawn portion of the credit facility. Interest expense in the Successor 2016 Period is comprised of interest expense incurred on the First Lien Exit Facility prior to the payment of the outstanding balance in October 2016 and commitment fees on the undrawn portion of the First Lien Exit Facility and letters of credit. During the Predecessor 2016 Period, we recorded interest expense on our Senior Secured Notes, Senior Unsecured Notes, and senior credit facility prior to the Chapter 11 filings, and recorded fees on our letters of credit, and interest expense and commitment fees on our senior credit facility after the Chapter 11 filings through the emergence date. 

Gain on extinguishment of debt was recognized for the year ended December 31, 2018 as a result of writing off the unamortized premium in conjunction with the repayment of the Building Note during the first quarter of 2018.

We recognized a gain on extinguishment of debt of $41.2 million in the Predecessor 2016 Period, primarily in connection with the exchange of $232.1 million in aggregate principal amount ($77.8 million net of discount and including holders’ conversion feature liabilities) of the Convertible Senior Unsecured Notes for approximately 84.4 million shares of the Predecessor Company’s common stock during the first quarter of 2016. Further conversions of the Convertible Senior Unsecured Notes were stayed in May 2016 in conjunction with the filing of the Chapter 11 petitions.

See “Note 10 - Long-Term Debt” to the consolidated financial statements in Item 8 of this report for additional discussion of our long-term debt transactions.

Reorganization items in the Predecessor 2016 Period primarily consist of the net gain recorded on the cancellation of Predecessor Company debt upon emergence from Chapter 11. See “Note 2 - Summary of Significant Accounting Policies” to the consolidated financial statements included in Item 8 of this Report for further discussion of reorganization items.

During the year ended December 31, 2017, we reduced the valuation allowance associated with our deferred tax assets related to alternative minimum tax credits that became realizable as a result of a special tax election. Accordingly, we recorded an income tax benefit of $8.7 million in the year ended December 31, 2017. Tax expense and the effective tax rate for the Successor 2016 Period and the Predecessor 2016 Period were low as a result of the valuation allowance against our net deferred tax asset in each period.
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 Liquidity and Capital Resources

At December 31, 2018, our cash and cash equivalents, excluding restricted cash, were $17.7 million. Additionally, we had no debt outstanding under our $350.0 million credit facility and $5.2 million in outstanding letters of credit, which reduce the amount available under the credit facility. As of February 20, 2019, the Company had approximately $10.9 million in cash and cash equivalents, excluding restricted cash, an undrawn credit facility, and $5.2 million in outstanding letters of credit.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2019 include cash flow from operations, cash on hand and amounts available under our credit facility, as discussed in “—Credit Facility” below.

Our working capital deficit increased to $63.9 million at December 31, 2018, compared to $3.8 million at December 31, 2017, largely due to the repayment of the Building Note in the first quarter of 2018, employee termination benefits paid during the first quarter of 2018, cash paid on settlements of commodity derivative contracts and the acquisition of interests in certain Mid-Continent properties. This increase is partially offset by fluctuations in the timing and amount of collections of receivables and payments of accounts payable and accrued expenses, asset retirement obligation valuation adjustments related primarily to changes in estimated well lives, changes in derivative assets and liabilities due to quarterly mark-to-market adjustments, and proceeds received from the Permian Divestiture.

We intend to spend between $160.0 million and $180.0 million in our 2019 capital budget plan, with the majority of those expenditures being allocated to drilling and completion activities. We intend to fund capital expenditures and other commitments for the next 12 months using cash flow from our operations, borrowings under our credit facility and cash on hand. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.

Cash Flows

Our cash flows from operations are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile. For example, during the period from January 2014 through December 2018, the NYMEX settled price for oil fluctuated between a high of $107.26 per Bbl and a low of $26.21 per Bbl, and the month-end NYMEX settled price for gas fluctuated between a high of $5.56 per MMBtu and a low of $1.71 per MMBtu.

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

Cash flows for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016, are presented in the following table and discussed below (in thousands):
SuccessorPredecessorCombined
 Year Ended December 31,Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,Year Ended December 31,
 20182017201620162016
Cash flows provided by (used in) operating activities$145,514 $181,179 $65,595 $(112,077)$(46,482)
Cash flows used in investing activities(183,453)(245,724)(39,835)(167,690)(207,525)
Cash flows (used in) provided by financing activities(43,724)(8,218)(415,061)407,551 (7,510)
Net (decrease) increase in cash and cash equivalents$(81,663)$(72,763)$(389,301)$127,784 $(261,517)

Cash Flows from Operating Activities

The $35.7 million decrease in operating cash flows for the year ended December 31, 2018 compared to 2017, is primarily due to (i) cash paid for employee termination benefits, (ii) cash paid on settlement of derivative contracts in 2018
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compared to receiving cash in 2017, and (iii) other changes in working capital, partially offset by lower general administrative costs.

The $227.7 million increase in operating cash flows for the year ended December 31, 2017 compared to 2016, is primarily due to (i) a reduction in cash paid for interest expense, (ii) a decrease in professional and other fees paid in connection with our restructuring in 2016, (iii) a reduction in payroll and other employee related general and administrative costs, (iv) a reduction 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 were partially offset by reductions in cash received for the settlement of derivatives and lower revenues in 2017 compared to 2016.

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

Cash Flows from Investing Activities

We dedicate and expect to continue to dedicate a substantial portion of our capital expenditure program toward the exploration for and development of our oil and natural gas properties. These capital expenditures are necessary to offset inherent declines in production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. During the year ended December 31, 2018, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities and cash paid for the acquisition of interests in certain Mid-Continent properties. These expenditures were partially offset by cash proceeds received for the Permian Divestiture and other non-core asset divestitures in 2018.

During the year ended December 31, 2017, cash flows used in investing activities consisted primarily of capital expenditures for our exploration and development operations and the acquisition of 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash, 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.

During the combined year ended December 31, 2016, cash flows used in investing activities consisted primarily of capital expenditures for our exploration and development operations.

Capital Expenditures. 

Our capital expenditures, on an accrual basis, for the years ended December 31, 2018 and 2017, the Successor 2016 Period, the Predecessor 2016 Period and the combined year ended December 31, 2016 are summarized below (in thousands):
 
SuccessorPredecessorCombined
 

Year Ended December 31,

Year Ended December 31,
Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,

Year Ended December 31,
 20182017201620162016
Capital Expenditures (on an accrual basis)
Drilling and completion$158,695 $194,388 $26,445 $153,863 $180,308 
Leasehold and geophysical11,680 51,645 11,617 1,764 13,381 
Other - operating419 854 2,901 3,108 6,009 
Other - corporate392 1,358 83 2,672 2,755 
Capital expenditures, excluding acquisitions171,186 248,245 41,046 161,407 202,453 
Acquisitions24,764 48,312 — 1,328 1,328 
Total$195,950 $296,557 $41,046 $162,735 $203,781 

Capital expenditures, excluding acquisitions, for exploration and development activities decreased for the year ended December 31, 2018 compared to 2017, primarily resulting from our lower capital expenditures budget and planned reduction in drilling activity as well as reductions in drilling costs in 2018.

Capital expenditures, excluding acquisitions, for exploration and development activities increased for the year ended December 31, 2017 compared to 2016, primarily due to drilling longer laterals in the North Park Basin, which are more capital intensive.

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Cash Flows from Financing Activities

Our financing activities used $43.7 million of cash for the year ended December 31, 2018, which consisted primarily of repaying the Building Note and cash paid for employee tax obligations in connection with the withholding of common shares upon vesting of employee share-based compensation awards.

Our financing activities used $8.2 million of cash for the year ended December 31, 2017, which consisted primarily of cash paid for employee tax obligations in connection with the withholding of common shares upon the vesting of employee share-based compensation awards and deferred financing costs incurred on the credit facility.

Cash used in financing activities for the year ended December 31, 2016, was insignificant, primarily due to the net effect of borrowings and repayments under the First Lien Exit Facility, as well as proceeds received from the Building Note, which were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan.

Indebtedness

Credit Facility

We had no debt outstanding under our credit facility at December 31, 2018. The borrowing base under the credit facility is $350.0 million, which was reduced from $425.0 million during the October 2018 borrowing base redetermination. The next semi-annual borrowing base redetermination is scheduled for April 1, 2019. The credit facility matures on March 31, 2020. The credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all proved reserves included in the Company's most recently delivered reserve report, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing).

The credit facility requires us to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. We were in compliance with all applicable financial covenants under the credit facility as of December 31, 2018.

The credit facility contains customary affirmative and negative covenants, including compliance with certain laws (including environmental laws, ERISA and anti-corruption laws), maintaining required insurance, delivering quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on incurring liens and indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants.

The credit facility includes events of default relating to customary matters, including, among other things: nonpayment of principal, interest or other amounts, violation of covenants, incorrectness of representations and warranties in any material respect, cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more, bankruptcy, judgments involving a liability of $25.0 million or more that are not paid, and ERISA events. Many events of default are subject to customary notice and cure periods.

Building Note

On the Emergence Date, we entered into the Building Note, which had an initial principal amount of $35.0 million and was secured by first priority mortgages on our real estate in Oklahoma City, Oklahoma. We repaid the Building Note in full during February 2018. The Building Note was recorded at fair value ($36.6 million) upon implementation of fresh start accounting, and approximately $1.3 million in in-kind interest costs were added to the principal prior to interest becoming payable in cash after the refinancing of the First Lien Exit Facility. The Building Note was set to mature on October 2, 2021, and was prepayable in whole or in part without premium or penalty.

See “Note 10 - Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt.

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Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2018, our contractual obligations included third-party drilling rig agreements, asset retirement obligations, operating 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.

As of December 31, 2018, 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 years3-5 years
More than
5 years
 (In thousands)
Third-party drilling rig agreements(1)
$3,595 $3,595 $— $— $— 
Asset retirement obligations(2)60,064 25,393 4,703 1,235 28,733 
Leases and other4,833 1,635 1,798 650 750 
Total$68,492 $30,623 $6,501 $1,885 $29,483 
____________________
1.Includes drilling contracts with third-party drilling rig operators at specified day or footage rates and termination fees associated with our hydraulic fracturing services agreements. All of our drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance.
2.Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2018. Certain of these estimates and assumptions are inherently unpredictable and will differ from actual results given the uncertainty regarding the timing of such expenditures. As a result, we do not expect to incur all of the estimated costs for the current asset retirement obligation shown above in the next year, and have budgeted $4.5 million for actual expected plugging and abandonment costs in 2019.

Valuation Allowance

Upon emergence from bankruptcy and the application of fresh start accounting, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had significant U.S. federal net operating losses remaining after the attribute reduction caused by the restructuring transactions. As such, the Successor Company had significant deferred tax assets to consume upon emergence. We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be 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, 2018.

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

In determining whether to maintain the valuation allowance at December 31, 2018, 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, 2018, 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, 2018.

See “Note 20 - Income Taxes” to the accompanying 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 management to make assumptions and prepare estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Estimates are based on historical experience and various other assumptions believed to be reasonable; however, actual results may differ significantly. The Company’s critical accounting policies and additional information on significant estimates are discussed below. See “Note 2—Summary of Significant Accounting Policies” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies.

Fresh Start Accounting. Upon emergence from bankruptcy, the Company applied fresh start accounting to its financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the plan of reorganization was less than the post-petition liabilities and allowed claims. Fresh start accounting was applied to the Company’s consolidated financial statements as of October 1, 2016. Under the principles of fresh start accounting, a new reporting entity was considered to have been created, and, as a result, the reorganization value of the Company was allocated to its individual assets, including property, plant and equipment, based on their estimated fair values. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after October 1, 2016, are not comparable with the financial statements prior to that date.

Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. 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 and issue long-term debt that contains embedded derivatives.

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. 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. The Company’s earnings may fluctuate significantly as a result of changes in fair value. Derivative assets and liabilities are netted whenever a legally enforceable master netting agreement exists 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.

Fair values of the substantial majority of the Company’s commodity derivative financial instruments are determined primarily by using discounted cash flow calculations or option pricing models, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be corroborated from active markets. Estimates of future prices are based upon published forward commodity price curves for oil and natural gas instruments. Valuations also incorporate adjustments for the nonperformance risk of the Company or its counterparties, as applicable.

Proved Reserves. Approximately 95.1% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2018. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control. Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data. The accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2018, 2017 and 2016, the Company revised its proved reserves from prior years’
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reports by approximately (33.2) MMBoe, 10.9 MMBoe and (105.4) MMBoe, respectively, due to 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. Estimates of proved reserves are key components of the Company’s financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect the Company’s future depreciation, depletion and impairment expenses.

Method of Accounting for Oil and Natural Gas Properties. The Company’s business is subject to accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. The Company uses the full cost method to account for its oil and natural gas properties. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Exploration and development costs include dry well costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil, natural gas and NGL reserves. Amortization of oil and natural gas properties is calculated using the unit-of-production method based on estimated proved oil, natural gas and NGL reserves. 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.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion and impairment of oil and natural gas properties are generally calculated on a well by well, lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method. As a result, the Company’s financial statements will differ from companies that apply the successful efforts method since the Company will generally reflect a higher level of capitalized costs as well as a higher oil and natural gas depreciation and depletion rate, and the Company will not have exploration expenses that successful efforts companies frequently have.

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, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, may not exceed an amount equal to the ceiling limitation. The Company calculates its full cost ceiling limitation using SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Successor Company recorded full cost ceiling 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 for the period from January 1, 2016 through October 1, 2016. No full cost ceiling impairment was recorded for the years ended December 31, 2018 and 2017. See “—Consolidated Results of Operations” for additional discussion of full cost ceiling impairments.

Unproved Properties. The balance of unproved properties consists primarily of costs to acquire unproved acreage. These costs are initially excluded from the Company’s amortization base until it is known whether proved reserves will or will not be assigned to the property. The Company assesses all properties, on an individual basis or as a group if properties are individually insignificant, classified as unproved on a quarterly basis for possible impairment or reduction in value. 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 if proved reserves are assigned. 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. For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a three to five year period from the original lease date. For leases that are held by production, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a 10-year period from the original lease date.

Property, Plant and Equipment, Net. Other capitalized costs including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. 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 7 to 39 years for
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buildings and 1 to 27 years for the electrical infrastructure assets and other equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in operations. 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 or asset group 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. If an asset or asset group is determined to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. 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. The Company may also determine fair value by using 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 value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.

See “—Consolidated Results of Operations” and “Note 8—Impairment” to the Company’s 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.

Revenue Recognition. Sales of oil, natural gas and NGLs 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, net of royalties, discounts and allowances, as applicable. The Successor Company deducts transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production tax expense in the consolidated statements of operations. See "Note 17—Revenues" to the Company's consolidated financial statements in Item 8 of this report for further information on the Company's accounting policies related to revenues.

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 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, 2018, 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 2—Summary of Significant Accounting Policies” to the Company’s 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, 2018, our commodity derivative contracts consisted of natural gas fixed price swaps under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.

Our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period and are settled in the production month.

At December 31, 2018, our open commodity derivative contracts consisted of the following:

Natural Gas Price Swaps 
Notional (MMcf)
Weighted Average
Fixed Price
January 2019 - March 20194,500 $4.28 

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

We recorded loss (gain) on commodity derivative contracts of $17.2 million and $(24.1) million for the years ended December 31, 2018 and 2017, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments (receipts) upon settlement of $35.3 million and $(7.3) million, respectively. Approximately $0.8 million of the payments made in 2018 relate to early settlements due to unwinding all outstanding oil derivative contracts in December 2018.

We recorded loss on commodity derivative contracts of $25.7 million and $4.8 million for the Successor 2016 Period and the Predecessor 2016 Period, respectively, as reflected in the consolidated statements of operations in Item 8 of this report, which includes net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. The net receipts for the Predecessor 2016 Period include early settlements after the Chapter 11 filings occurred, resulting in $17.9 million of cash receipts.

In December 2018, we entered into early settlements of all open crude oil swaps covering nine thousand bbls/day of production in December 2018 at an average strike price of $56.12, and five thousand bbls/day of production during 2019 at an average strike price of $54.29. Simultaneously, we entered into natural gas swaps for the first quarter of 2019. The Board and our management are continuing to evaluate the futures market for oil and natural gas in an attempt to protect short-term cash flow and to mitigate exposure to adverse oil and natural gas price changes.

See “Note 11—Derivatives” to the consolidated financial statements in Item 8 of this report for additional information regarding our commodity derivatives.

Credit Risk. 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
65

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. Our derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty.

Both the default under the Predecessor’s senior credit facility and the Chapter 11 filing constituted defaults under our commodity derivative contracts. As a result, certain commodity derivative contracts were settled prior to their contractual maturities in the second quarter of 2016 after the Chapter 11 filings occurred.

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, 2018, the counterparties to our open commodity derivative contracts consisted of four financial institutions, all of which are also lenders under the credit facility. As a result, we are not required to post additional collateral under our commodity derivative contracts.

Interest Rate Risk. We are exposed to interest rate risk on our credit facility. This variable interest rate on our credit facility fluctuates, and exposes us to short-term changes in market interest rates as our interest obligations on this instrument is periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate. We had no outstanding variable rate debt as of December 31, 2018.


66

Item 8.  Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 Page(s)

67

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, 2018. 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, 2018.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2018 has been audited by PricewaterhouseCoopers LLP an independent registered public accounting firm, as stated in its report which appears herein.
 
/s/    PAUL D. MCKINNEY       
 
/s/    MICHAEL A. JOHNSON       
Paul D. McKinney
President and Chief Executive Officer
 
Michael A. Johnson
Senior Vice President and Chief Financial Officer

68

Report of Independent Registered Public Accounting Firm

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

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of SandRidge Energy, Inc. and its subsidiaries (Successor) (the "Company") as of December 31, 2018 and 2017, and the related consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows for the years then ended and for the period from October 2, 2016 through December 31, 2016, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for the years then ended and for the period from October 2, 2016 through December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis of Accounting

As discussed in Note 1 to the consolidated financial statements, the United States Bankruptcy Court for the district of Southern Texas confirmed the Company's Amended Joint Chapter 11 Plan of Reorganization (the "plan") on September 9, 2016. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before October 1, 2016 and substantially alters or terminates all rights and interests of equity security holders as provided for in the plan.  The plan was substantially consummated on October 4, 2016 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of October 1, 2016.

Basis for Opinions

The Company'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's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 audits to obtain reasonable assurance about whether the consolidated financial 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.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated 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 consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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
69

accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) 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) 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) 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/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
March 5, 2019


We have served as the Company’s auditor since 2005. 

70

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated statements of operations, changes in stockholders’ equity (deficit) and cash flows present fairly, in all material respects, the results of operations and cash flows of SandRidge Energy, Inc. and its subsidiaries (Predecessor) (the "Company") for the period from January 1, 2016 to October 1, 2016 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company filed a petition on May 16, 2016 with the United States Bankruptcy Court for the district of Southern Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Amended Joint Chapter 11 Plan of Reorganization was substantially consummated on October 4, 2016 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting.


/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
March 3, 2017

71

SandRidge Energy, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except per share data)
 
December 31,
December 31,
 20182017
ASSETS
Current assets
Cash and cash equivalents$17,660 $99,143 
Restricted cash - other 1,985 2,165 
Accounts receivable, net45,503 71,277 
Derivative contracts5,286 1,310 
Prepaid expenses2,628 5,248 
Other current assets265 15,954 
Total current assets73,327 195,097 
Oil and natural gas properties, using full cost method of accounting
Proved1,269,091 1,056,806 
Unproved60,152 100,884 
Less: accumulated depreciation, depletion and impairment(580,132)(460,431)
749,111 697,259 
Other property, plant and equipment, net200,838 225,981 
Other assets1,062 1,290 
Total assets$1,024,338 $1,119,627 

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses$111,797 $139,155 
Derivative contracts— 10,627 
Asset retirement obligations25,393 41,017 
Other current liabilities— 8,115 
Total current liabilities137,190 198,914 
Long-term debt— 37,502 
Derivative contracts— 3,568 
Asset retirement obligations34,671 36,527 
Other long-term obligations4,756 3,176 
Total liabilities176,617 279,687 
Commitments and contingencies (Note 13)
Stockholders’ Equity
Common stock, $0.001 par value; 250,000 shares authorized; 35,687 issued and outstanding at December 31, 2018 and 35,650 issued and outstanding at December 31, 2017
36 36 
Warrants88,516 88,500 
Additional paid-in capital1,055,164 1,038,324 
Accumulated deficit(295,995)(286,920)
Total stockholders’ equity847,721 839,940 
Total liabilities and stockholders’ equity$1,024,338 $1,119,627 

The accompanying notes are an integral part of these consolidated financial statements.
72

SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Operations
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016 
(In thousands, except per share amounts)
 Successor Predecessor
 Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Revenues
Oil, natural gas and NGL$348,726 $356,210 $98,307 $279,971 
Other669 1,089 149 13,838 
Total revenues349,395 357,299 98,456 293,809 
Expenses
Production92,703 102,728 24,997 129,608 
Production taxes19,470 13,644 2,643 6,107 
Depreciation and depletion—oil and natural gas127,281 118,035 36,061 90,978 
Depreciation and amortization—other11,982 13,852 3,922 21,323 
Impairment4,170 4,019 319,087 718,194 
General and administrative41,666 76,024 9,837 116,091 
Accelerated vesting of employment compensation6,545 — — — 
Proxy contest7,139 — — — 
Terminated merger costs— 8,162 — — 
Employee termination benefits 32,657 4,815 12,334 18,356 
Loss (gain) on derivative contracts17,155 (24,090)25,652 4,823 
Loss on settlement of contract— — — 90,184 
Other operating (income) expense(998)479 268 4,348 
Total expenses359,770 317,668 434,801 1,200,012 
(Loss) income from operations(10,375)39,631 (336,345)(906,203)
Other (expense) income
Interest expense(2,787)(3,868)(372)(126,099)
Gain on extinguishment of debt1,151 — — 41,179 
Gain on reorganization items, net— — — 2,430,599 
Other income, net2,865 2,550 2,744 1,332 
Total other income (expense)1,229 (1,318)2,372 2,347,011 
(Loss) income before income taxes(9,146)38,313 (333,973)1,440,808 
Income tax (benefit) expense(71)(8,749)9 11 
Net (loss) income(9,075)47,062 (333,982)1,440,797 
Preferred stock dividends— — — 16,321 
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders
$(9,075)$47,062 $(333,982)$1,424,476 
(Loss) earnings per share
Basic$(0.26)$1.45 $(17.61)$2.01 
Diluted$(0.26)$1.44 $(17.61)$2.01 
Weighted average number of common shares outstanding
Basic35,057 32,442 18,967 708,928 
Diluted35,057 32,663 18,967 708,928 

The accompanying notes are an integral part of these consolidated financial statements.
73

SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016
 
Convertible
Perpetual
Preferred Stock
Common Stock
Additional
Paid-In
Capital
Treasury
Stock
Accumulated
Deficit
Non-controlling
Interest
Total
 SharesAmountSharesAmount
 (In thousands)
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.

74

SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity (Deficit)—Continued
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016
 Common StockWarrants
Additional
Paid-In
Capital
Accumulated
Deficit
Total
 SharesAmountSharesAmount
 
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 
Issuance of stock awards, net of cancellations
9 — — — — — — 
Common stock issued for general unsecured claims
28 — — — — — — 
Stock-based compensation
— — — — 24,276 — 24,276 
Issuance of warrants for general unsecured claims
— — 34 16 (16)— — 
Cash paid for tax withholdings on vested stock awards
— — — — (7,420)— (7,420)
Net loss
— — — — — (9,075)(9,075)
Balance at December 31, 2018 - Successor
35,687 $36 6,604 $88,516 $1,055,164 $(295,995)$847,721 

The accompanying notes are an integral part of these consolidated financial statements.
75

SandRidge Energy, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
For the Years Ended December 31, 2018 and 2017, the Period from October 2, 2016 through December 31, 2016 and the Period from January 1, 2016 through October 1, 2016 
(In thousands)
 
Successor
Predecessor 
 Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income
$(9,075)$47,062 $(333,982)$1,440,797 
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities
Provision for doubtful accounts
(462)406 (13,166)16,704 
Depreciation, depletion and amortization
139,263 131,887 39,983 112,301 
Impairment
4,170 4,019 319,087 718,194 
Gain on reorganization items, net
— — — (2,442,436)
Debt issuance costs amortization
470 430 — 4,996 
Amortization of discount, net of premium, on debt
(47)(330)(81)2,734 
Gain on extinguishment of debt
(1,151)— — (41,179)
Gain on debt derivatives
— — — (1,324)
Cash paid for early conversion of convertible notes
— — — (33,452)
Loss (gain) on derivative contracts
17,155 (24,090)25,652 4,823 
Cash (paid) received on settlement of derivative contracts
(35,325)7,260 7,698 72,608 
Loss on settlement of contract
— — — 90,184 
Cash paid on settlement of contract
— — — (11,000)
Stock-based compensation
23,377 15,750 6,250 9,075 
Other
(1,571)344 717 (3,260)
Changes in operating assets and liabilities increasing (decreasing) cash
Deconsolidation of noncontrolling interest
— — — (9,654)
Receivables
16,560 115 12,872 36,116 
Prepaid expenses
2,620 127 (1,079)(5,681)
Other current assets
170 191 (260)(181)
Other assets and liabilities, net
(1,754)4,186 1,505 (7,542)
Accounts payable and accrued expenses
(4,257)(2,199)990 (3,595)
Asset retirement obligations
(4,629)(3,979)(591)(61,305)
Net cash provided by (used in) operating activities
145,514 181,179 65,595 (112,077)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment
(187,047)(219,246)(51,676)(186,452)
Acquisitions of assets
(24,764)(48,312)— (1,328)
Proceeds from sale of assets
28,358 21,834 11,841 20,090 
Net cash used in investing activities
(183,453)(245,724)(39,835)(167,690)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings
10,000 — — 489,198 
Repayments of borrowings
(46,304)— (414,954)(74,243)
Debt issuance costs
— (1,488)— (333)
Proceeds from building mortgage
— — — 26,847 
Payment of mortgage proceeds and cash recovery to debt holders
— — — (33,874)
Cash paid for tax withholdings on vested stock awards
(7,420)(6,730)(110)(44)
Other
— — 3 — 
Net cash (used in) provided by financing activities
(43,724)(8,218)(415,061)407,551 
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH
(81,663)(72,763)(389,301)127,784 
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year
101,308 174,071 563,372 435,588 
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year
$19,645 $101,308 $174,071 $563,372 

The accompanying notes are an integral part of these consolidated financial statements.

76
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1. Voluntary Reorganization under Chapter 11 Proceedings

On May 16, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on the Emergence Date. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession through October 4, 2016. As such, the Company’s bankruptcy proceedings and related matters have been summarized below.

The Company was able to conduct normal business activities and pay associated obligations for the period following its bankruptcy filing and was authorized to pay and has paid certain pre-petition obligations, including employee wages and benefits, goods and services provided by certain vendors, transportation of the Company’s production, royalties and costs incurred on the Company’s behalf by other working interest owners. During the pendency of the Chapter 11 case, all transactions outside the ordinary course of business required the prior approval of the Bankruptcy Court.

Automatic Stay. Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. Absent an order from the Bankruptcy Court, substantially all of the Debtors’ pre-petition liabilities were subject to settlement under the Bankruptcy Code.

Plan of Reorganization. In accordance with the plan of reorganization confirmed by the Bankruptcy Court, the following significant transactions occurred upon the Company’s emergence from bankruptcy on October 4, 2016:

•First Lien Credit Agreement. All outstanding obligations under the senior credit facility were canceled, and claims under the senior credit facility received their proportionate share of (a) $35.0 million in cash and (b) participation in the newly established $425.0 million First Lien Exit Facility. Refer to Note 10 for additional information.

•Cash Collateral Account. The Company deposited $50.0 million of cash in a Cash Collateral Account. This deposit was released to the Company in February 2017 in conjunction with the refinancing of the First Lien Exit Facility.

•Senior Secured Notes. All outstanding obligations under the Senior Secured Notes were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of Common Stock issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal amount of newly issued Convertible Notes, which mandatorily converted into 14.1 million shares of Common Stock upon the refinancing of the First Lien Exit Facility in February 2017. Refer to Note 10 for additional information.

•General Unsecured Claims. The Company’s general unsecured claims, including the Unsecured Notes, became entitled to receive their proportionate share of (a) approximately $36.7 million in cash, (b) approximately 5.7 million shares of Common Stock, 5.2 million of which was issued immediately upon emergence, and (c) 4.9 million Series A Warrants, 4.5 million issued immediately upon emergence, and 2.1 million Series B Warrants, 1.9 million issued immediately upon emergence. Refer to Note 14 for additional information.

•Building Note. The Building Note with a principal amount of $35.0 million ($36.6 million fair value on the Emergence Date), was issued and purchased on the Emergence Date for $26.8 million in cash, net of certain fees and expenses, by certain holders of the Senior Unsecured Notes. Proceeds received from the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan. Refer to Note 10 for additional information.

•Preferred and Common Stock. The Company’s existing 7.0% and 8.5% convertible perpetual preferred stock and common stock were canceled and released under the Plan without receiving any recovery on account thereof.

2. Summary of Significant Accounting Policies

Fresh Start Accounting. Upon emergence from bankruptcy, the Company applied fresh start accounting to its financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of the Company’s assets immediately prior to confirmation of the plan of reorganization was less than the post-petition liabilities and allowed claims.

77
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The Company elected to apply fresh start accounting effective October 1, 2016, to coincide with the timing of its normal fourth quarter reporting period, which resulted in SandRidge becoming a new entity for financial reporting purposes. The Company evaluated and concluded that events between October 1, 2016, and October 4, 2016, were immaterial and use of an accounting convenience date of October 1, 2016, was appropriate. As such, related fresh start adjustments are included in the accompanying statement of operations for the Predecessor 2016 Period. As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the financial statements for the Successor 2016 Period will not be comparable with the financial statements prior to that date. 

Reorganization Value. Reorganization value represented the fair value of the Successor Company’s total assets on the Emergence Date and approximated the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh start accounting, the Company allocated the reorganization value to its individual assets based on their estimated fair values.

The Company’s reorganization value was derived from an estimate of enterprise value, which represented the estimated fair value of long-term debt and other interest-bearing liabilities and shareholders’ equity. In support of the Plan, the Company estimated the enterprise value of the Successor Company to be in the range of $1.0 billion to $1.3 billion, which was subsequently approved by the Bankruptcy Court. The Company estimated the final enterprise value to be approximately $1.1 billion. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections, third-party real estate reports, and applying standard valuation techniques, including net asset value analysis, precedent transactions analyses and public comparable company analyses.

The following table reconciles the enterprise value to the estimated reorganization value as of the Emergence Date (in thousands):
Enterprise value$1,089,808 
Plus: cash and cash equivalents563,372 
Plus: other working capital liabilities
131,766 
Plus: other long-term liabilities8,549 
Reorganization value of Successor assets$1,793,495 

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates included in this report are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.







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Reorganization Items

Reorganization items represent liabilities settled, net of amounts incurred, subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as gain on reorganization items, net in the accompanying consolidated statement of operations. The following table summarizes reorganization items for the Predecessor 2016 Period (in thousands):

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 settlements84,228 
Loss on mortgage(8,153)
Gain on preferred stock dividends37,893 
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 company with a principal focus on the acquisition, exploration and development of hydrocarbon resources in the United States.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. The Company proportionately consolidates the activities of the Royalty Trusts. 

Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.

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 NGL reserves; impairment tests of long-lived assets; the carrying value of unproved 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; 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.

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. 

Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the drilling, completion, and production of 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 collectibility of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are
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Notes to Consolidated Financial Statements - (Continued)
charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 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 accrued expenses. The carrying values of cash, trade receivables and trade payables are considered to reflect fair values due to the short-term maturity of these instruments. See Note 5 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. 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, third-party offers or prices of comparable assets with consideration of current market conditions to fair value its non-financial assets and liabilities when necessary.

Derivative Financial Instruments. The Company enters into oil and natural gas derivative contracts to manage risks related to fluctuations in prices of its expected oil and natural gas production. The Company considers current and anticipated market 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. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting 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 11 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, exploration and development activities and capitalized interest. The Successor Company capitalized gross internal costs of $8.8 million, $14.8 million and $4.0 million during the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, and the Predecessor Company capitalized internal costs of $22.7 million to the full cost pool during the Predecessor 2016 Period. 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 it has been determined that proved 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 amortized. The costs associated with unproved properties are primarily the costs to acquire unproved acreage. 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. 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 whether the proved reserves 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 unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

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Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed the ceiling limitation. A ceiling limitation calculation is performed at the end of each quarter. If 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 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 SEC prices adjusted for basis or location differentials, held constant over the life of the reserves. If applicable, these 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. 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.

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.

Property, Plant and Equipment, Net. Other capitalized costs, including other property and equipment, such as electrical infrastructure assets and buildings, are carried at cost or the fair value established on the Emergence Date. 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 7 to 39 years for buildings and 1 to 27 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.

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 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 8 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, 2018 the Company capitalized an insignificant amount of interest costs and in the year ended December 31, 2017, and the Successor 2016 Period, the Company did not capitalize any interest costs as capital expenditures were not financed with debt during these periods. During the Predecessor 2016 Period, the Company capitalized interest of approximately $2.2 million on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress.

Debt Issuance Costs. The Company includes unamortized line-of-credit debt issuance costs, if any, related to its 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. Debt issuance costs are amortized to interest expense over the term of the related debt. When debt is retired, any unamortized costs are written off and included in gain or loss on extinguishment of debt.

Investments. Investments in marketable equity securities at December 31, 2017 related to the Company’s then-outstanding non-qualified deferred compensation plan. The investments in this plan were designated as available for sale and measured at fair value using quoted prices readily available in the market (fair value option) which requires unrealized gains and losses be reported in earnings. Investments are included in other current assets and other assets in the accompanying consolidated balance sheet at December 31, 2017. The non-qualified deferred compensation plan was terminated and all remaining assets were paid to participants during the first quarter of 2018. See Note 5 and Note 16 for additional discussion of investments.

Asset Retirement Obligations. The Company owns oil and natural gas assets that require expenditures to plug, abandon and remediate associated property at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded at the estimated present value at the time the wells are drilled or
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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 asset is sold and 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 12 for further discussion of the Company’s asset retirement obligations.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs 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, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company made an accounting policy election on the Emergence Date to deduct transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $27.7 million, $29.1 million and  $7.4 million of transportation costs as a reduction from revenues in the years ended December 31, 2018 and 2017, and the Successor 2016 Period, respectively, versus presenting $26.2 million of these costs as production expenses in the Predecessor 2016 Period. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are included in production tax expense in the consolidated statements of operations. See Note 17 for further information on the Company's accounting policies related to revenues.

The Company accounts for natural gas production imbalances using the sales method, which recognizes revenue on all natural gas sold even though the natural gas volumes sold may be more or less than the 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 of $1.7 million and $1.6 million at December 31, 2018 and 2017, 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, equity compensation provided to employees directly involved in exploration 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.

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 interest expense.

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 and warrants, 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.

During the Successor 2016 Period, the Company assumed the conversion of the Convertible Notes to common stock under the if-converted method and determined if it was more dilutive than including the expense associated with the Convertible Notes in the computation of income available to common stockholders during the period the Convertible Notes were outstanding. The Predecessor Company also assumed the conversion of the preferred stock or Convertible Senior Unsecured Notes to common stock under the if-converted method and determined if it was more dilutive than including the preferred stock dividends or expense associated with the Convertible Senior Unsecured Notes, respectively, in the computation
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of income available to common stockholders. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 21 for the Company’s earnings per share calculation.

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 13 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, 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 the credit ratings of its commodity derivative counterparties on an ongoing basis and considers their credit default risk ratings in determining the fair value of its commodity derivative contracts. The Company’s commodity derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty.

If the Company defaults on its credit facility it will also default on commodity derivative contracts with counterparties that are lenders under the credit facility. The Company does not require collateral or other security from counterparties to support commodity derivative instruments. The Company has master netting agreements with all of its commodity derivative counterparties, which allow the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. 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 the counterparties under the commodity derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against any amounts owed to the same counterparty under the credit facility.

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 owners in the property for their share of those costs. The Company’s joint interest partners are primarily 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.

Purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, large oil and natural gas companies and gas pipeline companies. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect its ability to sell the oil, natural gas and NGLs it produces.

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The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):
Sales% of Revenue
December 31, 2018 - Successor
Targa Midstream Services L.P.$126,548 36.2 %
Plains Marketing, L.P.$102,182 29.2 %
Sinclair Crude Company $62,623 17.9 %
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 %

Recent Accounting Pronouncements. The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenues from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 to January 1, 2018, for the Company. The ASU required adoption using either the retrospective transition method, which required restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilized a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company adopted Topic 606 and all the related amendments (the “new revenue standard”) on January 1, 2018, using the modified retrospective transition method. See Note 17 for further discussion of the adoption of the new revenue standard.

The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory,” which removed the prohibition in ASC 740 against the immediate recognition of current and deferred income tax effects of intra-entity transfers of assets other than inventory. The amendments in this ASU were effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU required application on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company adopted the ASU on January 1, 2018. There was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarified that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company could have elected to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no uncompleted contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

The FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the disclosure Requirements for Fair Value Measurement," which removes, modifies or adds disclosure requirements regarding fair value measurements. The amendments in this ASU are effective for all entities beginning after December 15, 2019, with amendments on changes in unrealized gains and losses, the range and weighted average of significant unobservable inputs used 
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to develop Level 3 fair value measurements, and the narrative description of measurement uncertainty requiring prospective adoption and all other amendments requiring retrospective adoption. Early adoption is permitted and the Company elected to adopt this ASU during the third quarter of 2018, which resulted in a change to the Company's fair value measurement disclosures on a prospective basis, but had no impact on its consolidated financial statements.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” and other associated ASU's related to Topic 842 which requires lessees to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases will be classified as financing or operating expenses, with the classification affecting the pattern and classification of expense recognition in the income statement. Leases to explore for or use oil and natural gas are not impacted by this guidance. This topic is effective for the Company on January 1, 2019. Early adoption is permitted. 

Topic 842 provides a number of optional practical expedients in transition. The Company plans to elect the ‘package of practical expedients,’ and therefore will not have to reassess its prior conclusions about lease identification, lease classification and initial indirect costs. The Company also plans to elect the land easement practical expedient. The Company will also utilize the short-term lease recognition exemption, which means assets and liabilities will not be recognized for the rights and obligations of qualifying leases, including existing short-term leases of those assets in transition. The Company does not plan to elect the use-of-hindsight. Upon adoption, the Company anticipates (i) recognizing assets and liabilities for the rights and obligations of its vehicle and equipment leases and, (ii) providing new disclosures about the Company’s leasing activities. The Company has completed the implementation of a lease contract management system and is finalizing processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases on and after the date of adoption. The Company will adopt Topic 842 using a modified retrospective approach by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company is still finalizing its evaluation of the January 1, 2019 adoption. The impact to recognize the assets and liabilities for the rights and obligations of the Company's leases on the balance sheet is not expected to be material at adoption. New disclosures will be required in the first quarter of 2019 to present information related to the Company's leases, including the Company's short-term leases, which are not required to be presented on the balance sheet utilizing the short-term lease recognition exemption.

The FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments,” which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for the interim and annual periods beginning after December 31, 2018, and will be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company does not plan to early adopt and is currently evaluating the effect the guidance will have on its consolidated financial statements; however, the impact is not expected to be material.

3. Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):
 SuccessorPredecessor
 Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items$— $— $— $(55,606)
Cash paid for interest, net of amounts capitalized$(4,045)$(2,438)$(1,183)$(104,609)
Cash received (paid) for income taxes$4,381 $4,348 $— $(28)
Supplemental Disclosure of Noncash Investing and Financing Activities
Cumulative effect of adoption of ASU 2015-02$— $— $— $(247,566)
Property, plant and equipment transferred in settlement of contract
$— $— $— $215,635 
Change in accrued capital expenditures$(15,861)$(28,999)$10,630 $25,045 
Equity issued for debt$— $(268,779)$(13,001)$(4,409)

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4. Acquisitions and Divestitures of Oil and Gas Properties

Successor Acquisitions and Divestitures

2018 Divestitures

Divestiture of Permian Basin Properties. On November 1, 2018, the Company sold substantially all of its oil and natural gas properties, rights and related assets in the CBP region of the Permian Basin, primarily located in Andrews County, TX, along with 13,125,000 common units representing a 25% equity interest in the Permian Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments, and reduced its asset retirement obligations by approximately $26.9 million. The CBP assets and interest in the Permian Trust included 1,066 producing wells within the Permian Trust's area of mutual interest, certain wells not associated with the Permian Trust, a field office, and all equipment, inventory and yards associated with the Company's CBP operations. As a result of this divestiture, the Company no longer has any obligations associated with the Permian Trust. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the divestiture was accounted for as an adjustment to the full cost pool with no gain or loss recognized on the sale.

2018 Acquisitions

Acquisition of Oil and Natural Gas Interests. On November 2, 2018, the Company acquired an interest in certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $22.5 million in net consideration, net of post-closing adjustments, and assumed asset retirement obligations of approximately $6.4 million. The acquired assets primarily consist of interests in 1,199 producing wells, approximately 80% of which are operated by the Company, an additional 11.1% working interest in approximately 397,000 gross (44,000 net) acres across the Mid-Continent, and an additional 13.2% working interest ownership in the Company's saltwater gathering and disposal system in the Mississippian Lime. 

2017 Acquisitions

Acquisition of Properties. On February 10, 2017, the Company 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.

2017 Divestitures

2017 Property Divestitures. In 2017, the Company divested various non-core oil and natural gas properties for approximately $17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.

Predecessor Acquisitions and Divestitures

2016 Divestiture

Divestiture of West Texas Overthrust Properties and Release from Treating Agreement. In January 2016, the Company paid $11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental and was released from all past, current and future claims and obligations under an existing 30 year treating agreement between the companies. As of the date of the transaction, the Company had accrued approximately $111.9 million for penalties associated with shortfalls in meeting its delivery requirements under the agreement since it became effective in late 2012. The Company recognized a loss of approximately $89.1 million on the termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field and reduced its asset retirement obligations associated with its oil and natural gas properties by $34.1 million.

See Note 7 for discussion of non-oil and gas divestitures.



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5. Fair Value Measurements

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 included in the consolidated balance sheets approximated fair value at December 31, 2018, and December 31, 2017. 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 7.

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 these inputs requires judgment, which may affect the valuation and placement of these assets and liabilities within the fair value hierarchy levels. The market for the Company’s financial assets and liabilities, any associated credit risk and other factors are considered in calculating the fair values. 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 2 of the hierarchy as of December 31, 2018, and Level 1 and Level 2 as of December 31, 2017, as described below.

Level 1 Fair Value Measurements

Investments. The fair value of investments, which consisted of assets held in the Company’s non-qualified deferred compensation plan, was based on quoted market prices. See Note 2 and Note 16 for additional information.

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.

Fair Value - Recurring Measurement Basis

The following tables summarize the Company’s assets and liabilities measured at fair value on a recurring basis by the fair value hierarchy (in thousands):

December 31, 2018 
  Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value 
  Level 1 Level 2 Level 3 
Assets 
Commodity derivative contracts$— $5,286 $— $— $5,286 
$— $5,286 $— $— $5,286 
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December 31, 2017 
  Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value 
  Level 1 Level 2 Level 3 
Assets 
Commodity derivative contracts$— $5,582 $— (4,272)$1,310 
Investments5,072 — — — 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 
____________________
1.Represents the impact of netting assets and liabilities with counterparties where the right of offset exists. 

Transfers. During the years ended December 31, 2018 and 2017, the Successor 2016 Period and Predecessor 2016 Period, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

Fair Value of Financial Instruments - Long-Term Debt

The fair value of the Building Note was measured using a discounted cash flow analysis, which is classified as a Level 2 input in the fair value hierarchy. The Building Note was paid in full during the first quarter of 2018. The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands):
December 31, 2018December 31, 2017
  Fair Value Carrying Value Fair Value Carrying Value 
Building Note $— $— $42,526 $37,502 

See Note 10 for discussion of the Company’s long-term debt.

Fair Value of Non-Financial Assets and Liabilities

See Note 8 for discussion of the Company’s impairment valuations.

6. Accounts Receivable

A summary of accounts receivable is as follows (in thousands):
 December 31,
 20182017
Oil, natural gas and NGL sales$31,780 $35,301 
Joint interest billing13,083 29,505 
Oil and natural gas services604 639 
Other1,331 7,106 
Total accounts receivable46,798 72,551 
Less: allowance for doubtful accounts(1,295)(1,274)
Total accounts receivable, net$45,503 $71,277 

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The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands):
SuccessorPredecessor
 Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Beginning balance$1,274 $880 $— $4,847 
Additions charged to costs and expenses(1)758 397 880 16,695 
Deductions(2)(737)(3)— (751)
Impact of fresh start accounting— — — (20,791)
Ending balance$1,295 $1,274 $880 $— 
____________________
1.The Predecessor 2016 Period includes a $16.7 million addition for a joint interest account receivable after determining that future collection was doubtful when the joint interest owner filed for bankruptcy.
2.Deductions represent the write-off of receivables and collections of amounts for which an allowance had previously been established.

7. Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands): 
December 31,
20182017
Oil and natural gas properties
Proved$1,269,091 $1,056,806 
Unproved 60,152 100,884 
Total oil and natural gas properties1,329,243 1,157,690 
Less accumulated depreciation, depletion and impairment(580,132)(460,431)
Net oil and natural gas properties capitalized costs749,111 697,259 
Land 4,400 4,500 
Electrical infrastructure131,176 131,010 
Non-oil and natural gas equipment13,458 26,809 
Buildings and structures77,148 79,548 
Total 226,182 241,867 
Less accumulated depreciation and amortization (25,344)(15,886)
Other property, plant and equipment, net 200,838 225,981 
Total property, plant and equipment, net $949,949 $923,240 

The average rates used for depreciation and depletion of oil and natural gas properties were $10.32 per Boe in 2018, $7.92 per Boe in 2017, $8.31 per Boe in the Successor 2016 Period and $6.05 per Boe in the Predecessor 2016 Period.

See Note 8 for discussion of impairment of other property, plant and equipment.

The Company had approximately $10.6 million in assets classified as held for sale in the other current assets line of the accompanying consolidated balance sheet at December 31, 2017. Approximately $9.3 million of this total was related to one of the Company’s properties located in downtown Oklahoma City, OK, which was classified as held for sale in the fourth quarter of 2017 and sold during the second quarter of 2018 for a net amount of approximately $10.4 million, including transaction fees. The resulting gain of $1.1 million was recorded in other operating expense on the accompanying condensed consolidated statements of operations for the year ended December 31, 2018. 

Additionally, during the first quarter of 2018, the Company classified its remaining midstream generator assets as held for sale. These assets had a carrying value of $5.7 million which exceeded the estimated net realizable value of $1.6 million 
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based on expected sales prices obtained from third parties. As a result, the Company recorded an impairment of $4.1 million for the year ended December 31, 2018. The midstream generator assets were sold during the second quarter of 2018 with no gain or loss recognized on the sale. No significant assets were classified as held for sale at December 31, 2018.

Costs Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2018 (in thousands):
  Year Cost Incurred
 Total2018201720162015 and Prior
Property acquisition$59,522 $3,859 $20,647 $13,735 $21,281 
Exploration630 13 323 243 51 
Total costs incurred$60,152 $3,872 $20,970 $13,978 $21,332 

For leases that do not have existing production that would otherwise extend the lease term, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a three to five year period from the original lease date. For leases that are held by production, the Company estimates that any associated unproved costs will be evaluated and transferred to the amortization base of the full cost pool within a 10-year period from the original lease date. In addition, the Company’s internal engineers evaluate all properties on a quarterly basis.

8. Impairment

The Company analyzes various property, plant and equipment for impairment when certain triggering events occur by comparing the carrying values of the assets to their estimated fair values. Estimated fair values of drilling, midstream, electrical transmission and other assets were determined in accordance with the policies discussed in Note 2.

Impairment for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period consists of the following (in thousands):
SuccessorPredecessor
Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Full cost pool ceiling limitation(1)(2)$— $— $319,087 $657,392 
Drilling assets(3)(4)22 4,019 — 3,511 
Electrical infrastructure assets(5)— — — 55,600 
Midstream assets(6)4,148 — — 1,691 
$4,170 $4,019 $319,087 $718,194 
____________________
1.Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting, whereby the fair value of the Successor Company full cost pool was determined based upon forward strip oil and natural gas prices as of the Emergence Date. Because these prices were higher than the 12-month weighted average prices used in the full cost ceiling limitation calculation at December 31, 2016, the Successor Company incurred a ceiling test impairment.
2.Impairment recorded for the Predecessor Company in 2016 was due to full cost ceiling limitations recognized in each of the first three quarters of 2016. The impairment recorded in 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.
3.Impairment recorded in the years ended December 31, 2018 and 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value.
4.Impairment recorded in the Predecessor 2016 Period resulted from the write-down of certain drilling assets after the Company discontinued drilling operations in the Permian region.
5.Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage. 
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6.Impairment recorded in 2018 reflects the write down of midstream generator assets classified as held for sale to the net realizable value. The impairment recorded in the Predecessor 2016 Period resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a CO2 compressor station after determining that their future use was limited.

9. Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):
 December 31,
 20182017
Accounts payable and other accrued expenses$78,219 $90,423 
Payroll and benefits12,891 21,475 
Production payable12,767 18,059 
Taxes payable5,350 3,983 
Drilling advances2,031 3,830 
Accrued interest539 1,385 
Total accounts payable and accrued expenses$111,797 $139,155 

10. Long-Term Debt

Long-term debt consists of the following (in thousands):
December 31,
20182017
Credit facility
$— $— 
Building Note— 37,502 
Total debt— 37,502 
Less: current maturities of long-term debt — — 
Long-term debt $— $37,502 

Credit Facility. On February 10, 2017, the Company's First Lien Exit Facility was refinanced and replaced by a new $600.0 million credit facility with a $425.0 million available borrowing base. The borrowing base under the credit facility was reduced from $425.0 million to $350.0 million during the October 2018 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, 2019. The credit facility matures on March 31, 2020. 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 credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all the Company's proved reserves included in the reserve report most recently provided to the lenders, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing).

As of the end of each fiscal quarter, the credit facility requires the Company to maintain (i) a maximum consolidated total net leverage ratio of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio of no less than
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2.25 to 1.00. These financial covenants are subject to customary cure rights. The Company was in compliance with all applicable financial covenants under the credit facility at the end of each fiscal quarter in 2018.

The credit facility contains customary affirmative and negative covenants, including compliance with certain laws (including environmental laws, ERISA and anti-corruption laws), maintaining required insurance, delivering quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on incurring liens and indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. The Company was in compliance with these covenants as of December 31, 2018.

The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving a liability of $25.0 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.

Changes in the composition of the Company's Board resulting from the 2018 annual meeting in June 2018 may have been an event of default under the change in control provisions in the credit facility. However, the Company entered into a consent and waiver agreement with the administrative agent and certain lenders constituting the majority lenders under the credit facility. The consent and waiver agreement waived any event of default which might have occurred as a result of the change in the composition of the members of the Company’s Board and recognized the new members of the Board as existing members of the Board under the definition of change in control in the credit agreement.

The Company had no amounts outstanding under the credit facility at December 31, 2018 and $5.2 million in outstanding letters of credit, which reduce availability under the credit facility on a dollar-for-dollar basis.

First Lien Exit Facility. On the Emergence Date, the Company entered into the First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender. The First Lien Exit Facility had a borrowing base of $425.0 million and was set to mature on February 4, 2020. Outstanding borrowings bore interest at a rate equal to 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. Quarterly commitment fees were 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. 

Convertible Notes. As discussed in Note 1, on the Emergence Date, pursuant to the terms of the Plan, the Company issued approximately $281.8 million principal amount of Convertible Notes, which did not bear regular interest and were set to mature and mandatorily convert into shares of Common Stock on October 4, 2020, unless repurchased, redeemed or converted prior to that date. Under fresh start accounting, the Convertible Notes were recorded at their fair value of $445.7 million, which resulted in a premium of $163.9 million being recorded to additional paid in capital. The Company’s obligations pursuant to the Convertible Notes were fully and unconditionally guaranteed, jointly and severally, by each of the guarantors of the First Lien Exit Facility.

The Convertible Notes were initially convertible at a conversion rate of 0.05330841 shares of Common Stock per $1.00 principal amount of Convertible Notes, which represented, approximately 15.0 million total shares of common stock. The conversion rate was subject to customary anti-dilution adjustments. Convertible Notes holders could convert them at any time up to, and including, the business day prior to the maturity date. Between the Emergence Date and December 31, 2016, holders requested conversion of approximately $13.0 million of the Convertible Notes into approximately 0.7 million shares of Common Stock. Additionally, from January 1, 2017 to February 9, 2017, holders requested conversion of approximately $5.1 million of the Convertible Notes into approximately 0.3 million shares of Common Stock. The remaining $263.7 million par value of outstanding Convertible Notes mandatorily converted into 14.1 million shares of Common Stock when the First Lien Exit Facility was refinanced on February 10, 2017, after the determination by the Successor Company’s board of directors in good faith that: (a) the refinancing provided for terms that were materially more favorable to the Company and (b) causing a conversion was not the primary purpose of the refinancing.

Building Note. As discussed in Note 1, on the Emergence Date, the Company entered into the Building Note which had an initial principal amount of $35.0 million, and was set to mature on October 2, 2021. The Company sold the Building Note for net proceeds of $26.8 million which were then remitted to unsecured creditors on the Emergence Date. The Company repaid the Building Note in full in February 2018. Interest was payable on the Building Note at 6% per annum for the first year
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following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. Interest costs were payable in-kind until 90 days after the refinancing of the First Lien Exit Facility. Approximately $1.3 million in in-kind interest costs were added to the Building Note principal from the Emergence Date through May 11, 2017. Interest became payable in cash after that date. The Building Note became prepayable in whole or in part without premium or penalty when the First Lien Exit Facility was refinanced. Under fresh start accounting, the Building Note was initially recorded at a fair value of $36.6 million and the resulting premium was being amortized to interest expense over the term of the Building Note. When the Building Note was repaid, the remaining unamortized premium of $1.2 million was recognized as a gain on extinguishment of debt in the statement of operations for the year ended December 31, 2018.

11. 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. 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. On a quarterly basis, the commodity derivative contract valuations are adjusted to the mark-to-market valuation. At December 31, 2018, the Company’s commodity derivative contracts consisted of natural gas fixed price swaps. The Company receives a fixed price for these contracts and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Company recorded loss (gain) on commodity derivative contracts of $17.2 million and $(24.1) million for the years ended December 31, 2018 and 2017, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash payments (receipts) upon settlement of $35.3 million and $(7.3) million, respectively. Approximately $0.8 million of the payments made in 2018 relate to early settlements due to unwinding all oil derivative contracts in December 2018.

The Company recorded loss on commodity derivative contracts of $25.7 million and $4.8 million for the Successor 2016 Period and the Predecessor 2016 Period, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. The net receipts for the Predecessor 2016 Period include $17.9 million of cash receipts due to early settlements of certain derivative contracts after the Chapter 11 filings occurred.

In December 2018, we entered into early settlements of all open crude oil swaps covering nine thousand bbls/day of production in December 2018 at an average strike price of $56.12, and five thousand bbls/day of production during 2019 at an average strike price of $54.29. Simultaneously, the Company entered into natural gas swaps for the first quarter of 2019. The Board and management of the Company are continuing to evaluate the futures market for oil and natural gas in an attempt to protect short-term cash flow and to mitigate exposure to adverse oil and natural gas price changes. 

Master Netting Agreements and the Right of Offset. 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, 2018, the counterparties to the Company’s open commodity derivative contracts consisted of four financial institutions, all of which are also lenders under the Company’s credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as all of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s credit facility.
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The following tables summarize (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, the applicable portion of shared collateral under the credit facility as of December 31, 2018 and 2017 (in thousands):

December 31, 2018
Gross Amounts Gross Amounts Offset Amounts Net of OffsetFinancial Collateral Net Amount 
Assets 
Derivative contracts - current
$5,286 $— $5,286 $— $5,286 
Total
$5,286 $— $5,286 $— $5,286 

December 31, 2017 
Gross Amounts Gross Amounts Offset Amounts Net of OffsetFinancial Collateral Net Amount 
Assets 
Derivative contracts - current
$5,582 $(4,272)$1,310 $— $1,310 
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 $(14,195)$— 

At December 31, 2018, the Company’s open commodity derivative contracts consisted of the following:

Natural Gas Price Swaps 
Notional (MMcf)
Weighted Average
Fixed Price
January 2019 - March 20194,500 $4.28 

Fair Value of Derivatives 

The following table presents the fair value of the Company’s derivative contracts on a gross basis without regard to same-counterparty netting (in thousands):
December 31,December 31,
Type of Contract Balance Sheet Classification 20182017
Derivative assets 
Natural gas price swapsDerivative contracts - current$5,286 $5,582 
Derivative liabilities 
Oil price swapsDerivative contracts - current— (14,899)
Oil price swapsDerivative contracts - noncurrent— (3,568)
Total net derivative contracts $5,286 $(12,885)

See Note 5 for additional discussion of the fair value measurement of the Company’s derivative contracts.

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12. Asset Retirement Obligations

The following table presents the balance and activity of the Company’s asset retirement obligations (in thousands):
SuccessorPredecessor
Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Beginning balance$77,544 $106,481 $92,413 $103,578 
Liability incurred upon acquiring and drilling wells7,079 1,336 121 505 
Revisions in estimated cash flows(1)870 (28,565)12,397 — 
Liability settled or disposed in current period(2)(31,967)(11,308)(540)(36,979)
Accretion6,538 9,600 2,090 4,365 
Impact of fresh start accounting— — — 20,944 
Ending balance60,064 77,544 106,481 92,413 
Less: current portion25,393 41,017 66,154 65,678 
Asset retirement obligations, net of current$34,671 $36,527 $40,327 $26,735 
____________________
1.Revisions for the years ended December 31, 2018 and 2017, and the Successor 2016 Period relate primarily to changes in estimated well lives due to changes in oil and natural gas prices and changes in plugging cost estimates.
2.Liability settled or disposed for the year ended December 31, 2018 includes $26.9 million associated with the Permian Properties sold in November 2018. Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016.

13. Commitments and Contingencies 

Included below is a discussion of the Company's various future commitments as of December 31, 2018. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets.

Third-party drilling rig agreements. As of December 31, 2018, the Company had third-party drilling rig agreements with various terms extending to May 2019 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2018 total approximately $3.6 million.

Leases and other. As of December 31, 2018, the Company had commitments for leases and other agreements totaling approximately $4.8 million. These commitments are primarily for fleet vehicles, maintenance services, office equipment, and purchase obligations related to software services. Rental expense related to these leases was not significant for the years ended December 31, 2018, December 31, 2017, the Successor 2016 Period or the Predecessor 2016 Period.

Litigation and Claims. As previously disclosed, on May 16, 2016, the Debtors filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court confirmed the Plan on September 9, 2016, and the Debtors subsequently emerged from bankruptcy on October 4, 2016. 

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
• 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
• Barton W. Gernandt Jr., et al. v. SandRidge Energy, Inc., Case No. 5:15-cv-00834-D, USDC, Western District of
Oklahoma

On November 8, 2018, the court in the Gernandt case granted the defendants’ respective motions to dismiss and dismissed the action with prejudice.

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Notes to Consolidated Financial Statements - (Continued)
Although the remaining two Cases have not been dismissed against certain former officers and directors who remain defendants in the Cases, the Company remains as a nominal defendant in each of the Cases so that any of the respective plaintiffs may seek to recover proceeds from any applicable insurance policies or proceeds. In each of the Cases, to the extent liability exceeds the amount of available insurance proceeds, the Company may owe indemnity obligations to its former officers and/or directors who remain as defendants in such action. An estimate of reasonably probable losses associated with any of the Cases cannot be made at this time. The Company has not established any reserves relating to any of the Cases.

In addition to the matters 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. Pursuant to the terms of the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II, the Company is obligated to indemnify each Royalty Trust, for as long as the Trusts exist, against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters as stipulated in the respective agreements with each Royalty Trust.

14. Equity

Successor Equity

Common Stock and Performance Share Units. At December 31, 2018, the Company had 35.7 million shares of common stock, par value $0.001 per share, issued and outstanding, including 0.4 million shares of unvested restricted stock awards, and 250.0 million shares of common stock authorized. In accordance with normal practices, the Company granted additional restricted stock awards and an immaterial amount of performance share units in the third quarter of 2018.

Warrants. The Company has issued approximately 4.6 million Series A warrants and 2.0 million Series B warrants to certain holders of general unsecured claims as defined in the Plan. These warrants are exercisable until October 4, 2022 for one 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.

Poison Pill. On November 26, 2017, we entered into the Poison Pill. At our 2018 annual meeting in June 2018, the Poison Pill was terminated.

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.

Successor
Year Ended December 31, 2018Year Ended December 31, 2017 Period from October 2, 2016 through December 31, 2016 
Number of shares withheld for taxes495 349 5 
Value of shares withheld for taxes$7,420 $6,730 $110 

Predecessor Equity

Preferred Stock Dividends. Prior to the Chapter 11 petition filings, dividends on the Company’s 8.5% and 7.0% convertible perpetual preferred stock could be paid in cash or with shares of the Company’s common stock at the Company’s election. 

The Company suspended payment of the cumulative dividend on its 7.0% convertible perpetual preferred stock during the third quarter of 2015 and suspended the semi-annual dividend on its 8.5% convertible perpetual preferred stock prior to the February 2016 semi-annual dividend payment date. The Company ceased accruing dividends on its 8.5% and 7.0% convertible perpetual preferred stock as of May 16, 2016, in conjunction with the Chapter 11 petition filings.




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Notes to Consolidated Financial Statements - (Continued)
Preferred stock dividend accruals in arrears prior to the Emergence Date for the Predecessor Company’s 8.5% and 7.0% convertible perpetual preferred stock were as follows (in thousands):
Predecessor 
Period from January 1, 2016 through October 1, 2016 
8.5% Convertible perpetual preferred stock 
Dividends in arrears $11,262 
7.0% Convertible perpetual preferred stock 
Dividends in arrears $21,000 

Paid and unpaid dividends included in the calculation of income available to the Company’s common stockholders and the Company’s basic earnings per share calculation for the Predecessor 2016 Period are presented in the accompanying consolidated statements of operations. Preferred stock dividends in arrears were eliminated on the Emergence Date with no recovery paid to holders.

See Note 21 for discussion of the Company’s (loss) earnings per share calculation.

15. Share-Based Compensation

As discussed in Note 1, the Predecessor Company’s common stock was canceled and the Successor Company issued new Common Stock on the Emergence Date. Accordingly, the Predecessor Company's then existing share-based compensation awards were also canceled, which resulted in the recognition of $5.9 million in previously unamortized expense related to these awards on the date of cancellation. Share based compensation for the Predecessor and Successor periods are not comparable.

Successor Share-Based Compensation 

Omnibus Incentive Plan. The Omnibus Incentive Plan became effective on the Emergence Date after the cancellation of the Predecessor Company’s share-based compensation awards. The Omnibus Incentive Plan 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, 2018, the Company had restricted stock awards and an immaterial amount of performance share units outstanding under the Omnibus Incentive Plan. Forfeitures for these awards are recognized as they occur.
 
Restricted Stock Awards. The Successor 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. Vesting for certain restricted stock awards was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. The majority of the remaining restricted stock awards vested in June 2018 as a result of the accelerated vesting event related to the change in the composition of the Board resulting from the 2018 annual meeting discussed in Note 18. The Company granted additional restricted stock awards in the second half of 2018. Outstanding restricted shares will generally vest over either a one-year period or three-year period.


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Notes to Consolidated Financial Statements - (Continued)
The following table presents a summary of the Successor Company’s unvested restricted stock awards:

Number of
Shares
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested restricted shares outstanding at October 1, 2016— $— 
Granted1,448 $24.32 
Vested(14)$24.32 
Forfeited / Canceled(27)$24.32 
Unvested restricted shares outstanding at December 31, 20161,407 $24.32 
Granted671 $19.97 
Vested(827)$23.23 
Forfeited / Canceled(146)$23.52 
Unvested restricted shares outstanding at December 31, 20171,105 $22.62 
Granted370 $16.00 
Vested(1,066)$22.63 
Forfeited / Canceled(44)$21.04 
Unvested restricted shares outstanding at December 31, 2018365 $16.07 

As of December 31, 2018, the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $4.7 million. The remaining weighted-average contractual period over which this compensation cost may be recognized is 2.2 years. The aggregate intrinsic value of restricted stock that vested during 2018 was approximately $16.0 million based on the stock price at the time of vesting.

Performance Share Units. In February 2017, the Company granted equity-classified awards in the form of performance share units. The vesting for certain performance share units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 18 and were settled in shares of the Company's common stock with one share of common stock being issued per performance share unit. In September 2018, the Company granted an immaterial amount of additional performance share units. The following table presents a summary of the Company's performance share units: 

Number of
Units		Fair Value per Unit at December 31, 2018
(In thousands)
Unvested performance share units outstanding at December 31, 2016 — 
Granted199 
Vested— 
Forfeited / Canceled(16)
Unvested performance share units outstanding at December 31, 2017183 
Granted111 
Vested(177)
Forfeited / Canceled(6)
Unvested performance share units outstanding at December 31, 2018111 $20.41 

The aggregate intrinsic value of performance share units that vested during the year ended December 31, 2018 was approximately $2.7 million based on the stock price at the time of vesting.


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Notes to Consolidated Financial Statements - (Continued)
Successor Incentive-Based Compensation

Performance Units. In October 2016, the Company granted liability-classified awards in the form of performance units. The vesting for certain performance units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018. All remaining units vested in June 2018 as a result of the accelerated vesting as discussed in Note 18 and were paid at the issuance value of $100 each. The value for previous vestings was determined by annual scorecard results. The following table presents a summary of the Company's performance units:

Number of
Units		Fair Value per Unit at December 31, 2018
(In thousands)
Unvested performance units outstanding at October 1, 2016— 
Granted97 
Vested(1)
Forfeited / Canceled(9)
Unvested performance units outstanding at December 31, 2016 87 
Granted— 
Vested(32)
Forfeited / Canceled(6)
Unvested performance units outstanding at December 31, 2017 49 
Granted— 
Vested(48)
Forfeited / Canceled(1)
Unvested performance units outstanding at December 31, 2018— — 

The aggregate intrinsic value of performance units that vested during the year ended December 31, 2018 was approximately $4.8 million.















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Notes to Consolidated Financial Statements - (Continued)
The following tables summarize the Successor Company's share and incentive-based compensation for the years ended December 31, 2018 and 2017, and the Successor 2016 Period (in thousands):
Recurring Compensation Expense(1) Executive Terminations(2) Reduction in Force(2) Accelerated Vesting(3) Total 
Year Ended December 31, 2018 
Equity-classified awards: 
Restricted stock awards $4,735 $8,140 $3,777 $5,181 $21,833 
Performance share units 619 1,056 158 610 2,443 
Total share-based compensation expense 5,354 9,196 3,935 5,791 24,276 
Liability-classified awards: 
Performance units 756 2,151 558 1,309 4,774 
Total share and incentive-based compensation expense 6,110 11,347 4,493 7,100 29,050 
Less: Capitalized compensation expense (482)— — (555)(1,037)
Share and incentive-based compensation expense, net $5,628 $11,347 $4,493 $6,545 $28,013 
Year Ended December 31, 2017 
Equity-classified awards: 
Restricted stock awards $14,731 $1,825 $— $— $16,556 
Performance share units 1,356 — — — 1,356 
Total share-based compensation expense 16,087 1,825 — — 17,912 
Liability-classified awards: 
Performance units 2,574 — — — 2,574 
Total share and incentive-based compensation expense 18,661 1,825 — — 20,486 
Less: Capitalized compensation expense (2,521)— — — (2,521)
Share and incentive-based compensation expense, net $16,140 $1,825 $— $— $17,965 
Period from October 2, 2016 through December 31, 2016
Equity-classified awards: 
Restricted stock awards $2,296 $— $4,285 $— $6,581 
Total share-based compensation expense 2,296 — 4,285 — 6,581 
Liability-classified awards: 
Performance units 528 — 737 — 1,265 
Total share and incentive-based compensation expense 2,824 — 5,022 — 7,846 
Less: Capitalized compensation expense (407)— — — (407)
Share and incentive-based compensation expense, net $2,417 $— $5,022 $— $7,439 
____________________
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.




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Notes to Consolidated Financial Statements - (Continued)
Predecessor Share-Based Compensation

Restricted Common Stock Awards. The Predecessor Company’s restricted common stock awards generally vested over a four-year period, subject to certain conditions, and were valued based upon the market value of the common stock on the date of grant. The following table presents a summary of the Predecessor Company’s unvested restricted stock awards.
Number of
Shares
Weighted-
Average Grant
Date Fair Value
(In thousands)
Unvested restricted shares outstanding at December 31, 20155,626 $4.85 
Granted— $— 
Vested(3,034)$5.34 
Forfeited / Canceled(2,592)$4.31 
Predecessor ending unvested restricted shares at October 1, 2016— $— 

The Predecessor Company issued share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the 2009 Plan. Total share-based compensation expense was measured using the grant date fair value for equity-classified awards and using the fair value at period end for liability-classified awards. The Predecessor Company recognized total share-based compensation expense of $11.2 million, of which $1.7 million was capitalized, for the Predecessor 2016 Period. Share-based compensation expense for the Predecessor 2016 Period includes $5.4 million for the accelerated vesting of 1.3 million restricted common stock awards related to the Predecessor Company’s reduction in workforce during the first quarter of 2016. There was no significant activity related to the Predecessor Company’s outstanding unvested restricted stock units, performance units and performance share units during the Predecessor 2016 Period.

16. 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 2018 and 2017 performance years. Potential payout percentages ranged from 0% to 200% of specified target levels based on actual performance. Payment for the 2018 performance year will be made in the first quarter of 2019 based on actual performance as determined by the Board of Directors relative to the targets specified in the plan. As of December 31, 2018, the Company had accrued approximately $6.6 million for the 2018 AIP. Payment of $8.7 million was made in the first quarter of 2018 for the 2017 performance year.

Performance Incentive Plan. In January 2016, the Company implemented a performance incentive plan which included long-term incentive awards, and provided for quarterly cash payments at a target percentage to participants based upon corporate performance goals with aggregate annual payout opportunity ranging from 0% to 200%. The first three quarterly cash payments were limited to no greater than target amounts with a cash make up payment in the first quarter of 2017 for actual performance based on the Company’s annual results. Under this plan, the Predecessor Company paid out approximately $17.8 million during the first two quarters of 2016 and the Successor Company paid out approximately $7.1 million during the fourth quarter of 2016 and approximately $15.8 million during the first quarter of 2017.

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 IRS. For the years ended December 31, 2018, and 2017, the Successor 2016 Period and the Predecessor 2016 Period, the Company made matching contributions to the plan equal to 100% on the first 10% of employee deferred wages, excluding incentive compensation, totaling $2.8 million, $3.6 million, $0.9 million and $4.9 million, respectively. The decrease in contributions is due primarily to reductions in force that occurred in 2017 and 2018. 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.

Deferred Compensation Plans. The Company maintained a non-qualified deferred compensation plan that allowed eligible highly compensated employees to elect to defer income exceeding the IRS annual limitations on qualified 401(k) retirement plans through December 31, 2016. The Company made insignificant matching contributions on non-qualified contributions for the Successor 2016 Period and the Predecessor 2016 Period. On December 31, 2016, the Successor Company began the process of terminating the non-qualified deferred compensation plan and no employee or employer contributions were made to the plan after that date. In accordance with the plan termination procedures, the $5.1 million of remaining assets
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Notes to Consolidated Financial Statements - (Continued)
in the plan as of December 31, 2017, were fully distributed to participating employees during the first quarter of 2018. These assets were included in other current assets in the consolidated balance sheet at December 31, 2017.

17. Revenues

The Company adopted the new revenue standard on January 1, 2018, using the modified retrospective method for all contracts outstanding on that date. Adoption of the new revenue standard had no impact on the Company’s consolidated balance sheet, results of operations, equity or cash flows as of the adoption date, and the Company does not expect any further material impact to its consolidated financial statements on an ongoing basis as a result of adopting the new revenue standard. The Company has included the disclosures required by the new revenue standard below.

The following table disaggregates the Company’s revenue by source for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands):

SuccessorPredecessor
Year Ended December 31,Year Ended December 31,Period from October 2, 2016 through December 31,Period from January 1, 2016 through October 1,
2018201720162016
Oil$214,651 $202,539 $57,093 $159,023 
NGL67,111 61,322 14,756 42,541 
Natural gas66,964 92,349 26,458 78,407 
Other669 1,089 149 13,838 
Total revenues$349,395 $357,299 $98,456 $293,809 

Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs and 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 tax 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, 2018, 2017 and 2016, the Company had revenues receivable of $31.8 million, $35.3 million and $42.6 million respectively, and did not record any bad debt expense on revenues receivable during the year ended December 31, 2018.

Practical expedients and exemptions. The Company elected not to retrospectively restate contracts that were modified prior to January 1, 2017, and assumed that the contract terms in place at January 1, 2018 were in place from the inception of the contract.

Most of the Company's contracts are short-term in nature with a contract term of one year or less. The Company generally expenses certain insignificant costs when incurred rather than recognizing them as an asset because the amortization period would have been one year or less. Additionally, the Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, and (ii) contracts for which revenue is recognized at the amount to which the Company has the right to invoice for services performed. Payment terms are typically within 30 days of control being transferred.
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Notes to Consolidated Financial Statements - (Continued)
Currently, the Company’s existing contracts do not contain financing components, but the Company has elected the practical expedient that allows financing components to be ignored if the difference between the performance and payment is less than one year for any future contracts that may contain financing components.

18. Proxy Contest

In the second quarter of 2018, the Company received notification from Carl C. Icahn and certain affiliated entities (together, "Icahn"), that they intended to nominate a full slate of candidates for election to the Board at the 2018 annual meeting that was held on June 19, 2018. The Company and Icahn, together with certain of their Board nominees, each entered into a settlement agreement which expanded the size of the Board to eight directors. Previous directors Sylvia K. Barnes, David J. Kornder and William M. Griffin, Jr. were re-elected, and Bob G. Alexander, Jonathan Christodoro, Jonathan Frates, John J. "Jack" Lipinski and Randolph C. Read were newly elected following the certification of the voting results, which occurred on June 22, 2018. As confirmed by general counsel, the election of a majority of non-incumbent directors nominated in connection with the proxy contest would result in the accelerated vesting of certain share and incentive-based compensation awards granted to the Company's employees and directors as discussed further in Note 15.

The Company incurred legal, consulting and advisory fees related to dealing with shareholders and the proxy contest of $7.1 million for the year ended December 31, 2018.


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Notes to Consolidated Financial Statements - (Continued)
19. Employee Termination Benefits

The following table presents a summary of employee termination benefits for the years ended December 31, 2018 and 2017, the Successor 2016 Period and the Predecessor 2016 Period (in thousands):

Cash Share-Based Compensation (6) Number of Shares Total Employee Termination Benefits 
Year Ended December 31, 2018 (Successor) 
Executive Employee Termination Benefits(1) $11,945 $9,196 554 $21,141 
Other Employee Termination Benefits(2) 7,581 3,935 209 11,516 
$19,526 $13,131 763 $32,657 
Year Ended December 31, 2017 (Successor) 
Executive Employee Termination Benefits(3) $2,500 $1,825 96 $4,325 
Other Employee Termination Benefits 490 — — 490 
$2,990 $1,825 96 $4,815 
Period from October 2, 2016 through December 31, 2016 (Successor)
Executive Employee Termination Benefits $— $1,591 73 $1,591 
Other Employee Termination Benefits(4) 8,048 2,695 118 10,743 
$8,048 $4,286 191 $12,334 
Period from January 1, 2016 to October 1, 2016 (Predecessor) 
Executive Employee Termination Benefits $810 $1,072 299 $1,882 
Other Employee Termination Benefits(5) 12,427 4,047 941 16,474 
$13,237 $5,119 1,240 $18,356 
____________________
1.On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018.
2.As a result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company.
3.Includes cash severance costs and share-based compensation costs associated with the accelerated vesting of awards related to the departure of the Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert.
4.As a result of a reduction in workforce in the fourth quarter of 2016, certain employees received termination benefits including cash severance and accelerated share and incentive-based compensation vesting upon separation of service from the Company.
5.As a result of a reduction in workforce in the first quarter of 2016 and discontinuing all remaining drilling and oilfield services operations and the majority of all midstream and marketing services operations in the first quarter of 2016, certain employees received termination benefits including cash severance and accelerated share-based compensation vesting upon separation of service from the Company.
6.Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reduction in workforce in the first quarter of 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the Company’s common stock was issued per performance share unit.

See Note 15 for additional discussion of the Company’s share-based compensation awards.

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Notes to Consolidated Financial Statements - (Continued)
20. Income Taxes

The Company’s income tax (benefit) provision consisted of the following components (in thousands):
 
Successor
Predecessor
 Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Current
Federal$(33)$(8,719)$— $— 
State(38)(30)9 11 
(71)(8,749)9 11 
Deferred
Federal— — — — 
State— — — — 
— — — — 
Total (benefit) provision $(71)$(8,749)$9 $11 

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):
SuccessorPredecessor
 Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Computed at federal statutory rate$(1,921)$13,409 $(116,891)$504,283 
State taxes, net of federal benefit119 (284)(3,696)10,512 
Non-deductible expenses849 1,711 144 462 
Non-deductible debt costs— — — 22,694 
Stock-based compensation1,874 1,109 306 5,884 
Discharge of debt and other reorganization related items206 1,018 — 359,278 
Return to provision adjustments (1)(1,292)341,681 — — 
Impact of legislative changes— 243,801 — — 
Release of valuation allowance— (8,719)— — 
Change in valuation allowance132 (602,452)120,144 (903,102)
Other(38)(23)2 — 
Total (benefit) provision $(71)$(8,749)$9 $11 
____________________
1.The adjustment for the period ended December 31, 2017, primarily related to the Company’s decision to file its 2016 income tax returns using an alternate method than previously estimated with respect to its Chapter 11 related transactions.

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 related to alternative minimum tax ("AMT") credits that became realizable as a result of a special tax election. Accordingly, the Company recorded an income tax benefit of $8.7 million in the year ended December 31, 2017. As a result of the significant weight placed on the Company’s cumulative negative earnings position, the Company continued to maintain the full valuation allowance against its remaining net deferred tax asset at December 31, 2017 and December 31, 2018.

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Notes to Consolidated Financial Statements - (Continued)
Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):
 December 31, 2018December 31, 2017
Deferred tax liabilities
Investments(1)$112,343 $171,517 
Derivative contracts1,128 — 
Total deferred tax liabilities113,471 171,517 
Deferred tax assets
Property, plant and equipment267,865 391,273 
Derivative contracts— 3,131 
Net operating loss carryforwards302,190 217,259 
Tax credits and other carryforwards35,640 33,001 
Asset retirement obligations15,016 18,843 
Other3,816 8,959 
Total deferred tax assets624,527 672,466 
Valuation allowance(511,056)(500,949)
Net deferred tax liability$— $— 
____________________
1.Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.

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 include, among others, a permanent reduction to the corporate income tax rate from a maximum 35% to a flat 21% rate, expansion of expensing capital expenditures for a period of time, new limitations on the utilization of net operating losses ("NOLs"), and limitations on the deduction of interest expense and executive compensation. Based on our analysis of the TCJA and guidance currently available we recorded income tax expense of approximately $243.8 million in the period ended December 31, 2017, which was completely offset by a decrease in the corresponding valuation allowance. The provisional amount primarily related to the remeasurement of our gross deferred tax assets and liabilities existing at December 31, 2017 at the appropriate tax rate expected to exist at the time of their reversal. We completed our analysis of the impact of the TCJA and recorded an immaterial adjustment to income tax expense in the year ended December 31, 2018, which was completely offset by an increase in the corresponding valuation allowance.

Internal Revenue Code ("IRC") Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, 2016 that subjected certain of the Company's tax attributes, including $1.9 billion of federal NOL carryforwards to the IRC Section 382 limitation. This limitation is expected to result in $1.6 billion of the $1.9 billion of federal NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance were reduced in the period ended December 31, 2017. The limitation did not result in a tax liability for the tax years ended December 31, 2016, December 31, 2017, or December 31, 2018. Since the October 4, 2016 ownership change, the Company has generated additional NOLs that are not currently subject to an IRC Section 382 limitation. See "Note 19 - Income Taxes" in the 2017 Form 10-K for additional discussion with respect to the impact of income tax elections associated with the Chapter 11 reorganization. 

As of December 31, 2018, the Company had approximately $1.1 billion of federal NOL carryforwards, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation. Of the $1.1 billion of federal NOL carryforwards, $0.8 billion expire during the years 2025 through 2037, while $0.3 billion do not have an expiration date. Additionally, the Company had federal tax credits in excess of $32.0 million which begin expiring in 2029.

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Notes to Consolidated Financial Statements - (Continued)
A reconciliation of the beginning and ending amount of the Company's unrecognized tax benefits is as follows (in thousands):
 Year Ended December 31, 2018 Year Ended December 31, 2017
Unrecognized tax benefit at January 1$48 $84 
Changes to unrecognized tax benefits related to a prior period— 2 
Lapse of statute of limitations(48)(38)
Unrecognized tax benefit at December 31$— $48 

Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included insignificant amounts of accrued gross interest with respect to unrecognized tax benefits in its accompanying consolidated statements of operations during the years ended December 31, 2017 and 2016, with none accrued in the year ended December 31, 2018.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2015 to present remain open for federal examination. Additionally, tax years 2005 through 2014 remain subject to examination for the purpose of determining the amount of federal NOL 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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Notes to Consolidated Financial Statements - (Continued)
21. (Loss) Earnings per Share

As discussed in Note 1, on the Emergence Date, the Predecessor Company’s then-authorized common stock was canceled and the new Common Stock and Warrants were issued.

The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted (loss) earnings per share:
Net (Loss) Income Weighted Average Shares (Loss) Earnings Per Share 
(In thousands, except per share amounts) 
Year Ended December 31, 2018 (Successor) 
Basic loss per share$(9,075)35,057 $(0.26)
Effect of dilutive securities
Restricted stock awards (1)— — 
Performance share units(1)— — 
Warrants(1)— — 
Diluted loss per share$(9,075)35,057 $(0.26)
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(2)— — 
Warrants(2)— — 
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 $(17.61)
Effect of dilutive securities
Restricted stock awards(3)— — 
Warrants(3)— — 
Convertible Notes (4)— — 
Diluted loss per share$(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(5)— — 
Diluted earnings per share$1,424,476 708,928 $2.01 
____________________
1.No incremental shares of potentially dilutive restricted stock awards, performance share units or warrants were included for the year ended December 31, 2018, as their effect was antidilutive under the treasury stock method.
2.No incremental shares of potentially dilutive performance share units or warrants were included for the year ended December 31, 2017, as their effect was antidilutive under the treasury stock method.
3.No incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive under the treasury stock method.
4.Potential common shares related to the Convertible Notes covering 14.6 million shares for the Successor 2016 Period were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.
5.No incremental shares of potentially dilutive restricted stock awards were included for the Predecessor 2016 Period as their effect was antidilutive under the treasury stock method.

See Note 15 for discussion of the Company’s share-based compensation awards.


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Notes to Consolidated Financial Statements - (Continued)
22. Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

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.

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,
 201820172016
Oil and natural gas properties
Proved$1,269,091 $1,056,806 $840,201 
Unproved60,152 100,884 74,937 
Total oil and natural gas properties1,329,243 1,157,690 915,138 
Less accumulated depreciation, depletion and impairment(580,132)(460,431)(353,030)
Net oil and natural gas properties capitalized costs$749,111 $697,259 $562,108 

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):
SuccessorPredecessor
 Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Acquisitions of properties
Proved$30,641 $7,092 $5,142 $3,897 
Unproved4,197 91,139 5,491 1,899 
Exploration1,940 8,850 — 1,234 
Development158,361 187,264 27,429 149,924 
Total cost incurred$195,139 $294,345 $38,062 $156,954 


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Notes to Consolidated Financial Statements - (Continued)
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 impact the Company’s operations have on actual net earnings.
SuccessorPredecessor
Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Revenues$348,726 $356,210 $98,307 $279,971 
Expenses
Production costs112,173 116,372 27,640 135,715 
Depreciation and depletion127,281 118,035 36,061 90,978 
Impairment — — 319,087 657,392 
Total expenses239,454 234,407 382,788 884,085 
Income (loss) before income taxes109,272 121,803 (284,481)(604,114)
Income tax expense (benefit) (1)28,520 47,722 (112,427)(229,986)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)
$80,752 $74,081 $(172,054)$(374,128)
____________________
1.Income tax expense (benefit) is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.

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.

The following table represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance
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Notes to Consolidated Financial Statements - (Continued)
with the SEC’s regulations. Over 90% of the Company’s proved reserves estimates have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.

Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2018, 2017 and 2016. Cawley, Gillespie & Associates, Ryder Scott and Netherland Sewell 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 existing 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.

2018 Activity. Proved reserves decreased from 177.6 MMBoe at December 31, 2017 to 160.2 MMBoe at December 31, 2018, primarily as a result of a one-time adjustment to future workover costs in the Company's Mississippian Lime wells. As its large population of Mississippian Lime wells transition into late-life mature production, the Company has experienced increasing operating costs which have been incorporated into its 2018 reserve report. This estimate of future costs contributed to a 24.9 MMBoe decrease associated with shorter economic lives. The Company also recorded a decrease of 8.3 MMBoe attributable to well performance and a decrease of 6.6 MMBoe due to divestitures of proved reserves. These reductions were partially offset by the acquisition of 15.4 MMBoe associated with the purchase of interests in Mid-Continent wells, extensions and discoveries of 19.3 MMBoe from successful drilling in the North Park Basin and to a lesser extent the NW STACK play in the Mid-Continent, as well as recording proved undeveloped reserves at an increased well density in the North Park Basin.

2017 Activity. During 2017, the Company recorded extensions and discoveries of 19.4 MMBoe, primarily from successful drilling in its NW STACK play in the Mid-Continent area and its North Park Basin properties, sold 1.9 MMBoe of proved reserves, and recorded upward revisions of 10.9 MMBoe, primarily as a result of significantly higher commodity prices in 2017 and minor revisions due to well performance.

2016 Activity. During 2016, on a pro forma combined basis, the Predecessor Company and Successor Company recognized total downward revisions of prior estimates of approximately 105.4 MMBoe, predominantly from revisions of approximately 94.7 MMBoe due to well performance and 12.1 MMBoe due to a decrease in commodity prices. The negative revisions from well performance were from the Mid-Continent area 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. These decreases were partially offset by approximately 7.8 MMBoe of extensions due to successful drilling.

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Notes to Consolidated Financial Statements - (Continued)
The summary below presents changes in the Company’s estimated reserves.
OilNGLNatural GasTotal
 (MBbls)(MBbls)(MMcf)(1)MBoe
Proved developed and undeveloped reserves
As of December 31, 2015(2) - Predecessor77,911 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 discoveries987 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 - Predecessor27,252 33,019 466,328 137,992 
Revisions of previous estimates23,978 1,139 915 25,270 
Extensions and discoveries2,868 448 10,309 5,034 
Production(1,214)(999)(12,770)(4,341)
As of December 31, 2016 - Successor52,884 33,607 464,782 163,955 
Revisions of previous estimates804 2,628 44,679 10,879 
Acquisitions of new reserves18 70 683 202 
Extensions and discoveries12,446 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 - Successor61,791 34,314 488,932 177,594 
Revisions of previous estimates(2,316)(8,952)(131,518)(33,188)
Acquisitions of new reserves2,146 4,131 54,436 15,350 
Extensions and discoveries11,148 2,320 35,185 19,332 
Sales of reserves in place(5,273)(809)(2,969)(6,577)
Production(3,477)(2,829)(36,175)(12,335)
As of December 31, 2018 - Successor64,019 28,175 407,891 160,176 
Proved developed reserves
As of December 31, 2015 - Predecessor48,639 51,089 964,617 260,498 
As of October 1, 2016 - Predecessor24,541 30,238 428,050 126,121 
As of December 31, 2016 - Successor25,911 29,290 393,028 120,706 
As of December 31, 2017 - Successor25,845 29,922 407,988 123,765 
As of December 31, 2018 - Successor18,693 22,302 307,845 92,303 
Proved undeveloped reserves
As of December 31, 2015 - Predecessor29,272 9,986 149,223 64,129 
As of October 1, 2016 - Predecessor2,711 2,781 38,278 11,872 
As of December 31, 2016 - Successor26,973 4,317 71,754 43,249 
As of December 31, 2017 - Successor35,946 4,392 80,944 53,829 
As of December 31, 2018 - Successor45,326 5,873 100,046 67,873 
____________________
1.Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
2.Includes proved reserves attributable to noncontrolling interests as shown in the table below:
 Predecessor
December 31,
 2015
Oil (MBbl)7,004 
NGL (MBbl)3,694 
Natural gas (MMcf)50,508 
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Notes to Consolidated Financial Statements - (Continued)
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"). 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;
•pricing is applied based upon SEC prices at December 31, 2018, 2017, and 2016 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,
 201820172016
Oil (per barrel)$60.86 $48.47 $38.59 
NGL (per barrel)$25.62 $20.28 $10.99 
Natural gas (per Mcf)$1.77 $1.90 $1.56 
•future development and production costs are determined based upon actual 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,
201820172016
Future cash inflows from production$5,339,265 $4,621,615 $3,136,762 
Future production costs(1,996,689)(1,837,852)(1,454,798)
Future development costs(1)(1,170,113)(966,203)(665,516)
Future income tax expenses (2)— (107)(142)
Undiscounted future net cash flows2,172,463 1,817,453 1,016,306 
10% annual discount(1,126,860)(1,068,159)(577,942)
Standardized measure of discounted future net cash flows
$1,045,603 $749,294 $438,364 
____________________
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.

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Notes to Consolidated Financial Statements - (Continued)
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):
SuccessorPredecessor
Year Ended December 31, 2018Year Ended December 31, 2017Period from October 2, 2016 through December 31, 2016Period from January 1, 2016 through October 1, 2016
Beginning present value $749,294 $438,364 $392,604 $1,314,562 
Changes during the year
Adoption of ASU 2015-02— — — (224,965)
Revenues less production(236,553)(239,838)(70,668)(144,256)
Net changes in prices, production and other costs316,095 347,458 35,684 (394,173)
Development costs incurred80,050 35,517 7,941 69,080 
Net changes in future development costs(11,483)(64,484)(291,232)436,041 
Extensions and discoveries102,961 112,556 14,986 12,449 
Revisions of previous quantity estimates(91,038)26,697 308,374 (728,254)
Accretion of discount70,576 37,226 9,375 91,337 
Net change in income taxes56 23 — 402 
Purchases of reserves in-place35,713 454 — — 
Sales of reserves in-place(2,029)(2,977)— (13,314)
Timing differences and other(1)31,961 58,298 31,300 (26,305)
Net change for the year296,309 310,930 45,760 (921,958)
Ending present value(2)$1,045,603 $749,294 $438,364 $392,604 
____________________
1.The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.
2.Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices.

23. Quarterly Financial Results (Unaudited)

The Company’s operating results for each quarter of 2018 and 2017 are summarized below (in thousands, except per share data).
First
Quarter
Second
Quarter
Third
Quarter
Fourth Quarter
2018
Total revenues$87,128 $79,462 $97,660 $85,145 
(Loss) income from operations(1)(2)$(41,967)$(33,685)$12,430 $52,847 
Net (loss) income(1)(2)$(40,894)$(34,074)$11,715 $54,178 
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
Basic$(1.18)$(0.97)$0.33 $1.53 
Diluted$(1.18)$(0.97)$0.33 $1.53 
____________________
1.Includes loss (gain) on derivative contracts of $18.3 million, $30.1 million, $11.3 million and $(42.6) million for the first, second, third and fourth quarters, respectively.
2.Includes employee termination benefits of $31.6 million for the first quarter, accelerated vesting of employment compensation of $6.5 million for the second quarter, and proxy contest costs of $7.2 million for the second quarter.


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Notes to Consolidated Financial Statements - (Continued)
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) 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)
____________________
1.Includes (gain) loss on derivative contracts of $(34.2) million, $(23.5) million, $11.7 million and $21.9 million for the first, second, third and fourth quarters, respectively.
2.Includes employee termination benefits of $4.4 million for the second quarter and terminated merger costs of $8.2 million for the fourth quarter.

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Notes to Consolidated Financial Statements - (Continued)
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, 2018 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, 2018 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.


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Notes to Consolidated Financial Statements - (Continued)
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, 2019: “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, 2019: “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, 2019: “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, 2019: “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, 2019.
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Notes to Consolidated Financial Statements - (Continued)
PART IV
 
Item 15.  Exhibits and Financial Statement Schedules

The following documents are filed as a part of this report:
1.Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements appearing on page 67. 
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-K 001-33784 2.1 1/9/2014 
2.2 8-A 001-33784 2.1 10/4/2016 
2.3**

8-K001-337842.1 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-K001-337843.1 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 10/4/2016
4.5 

8-K001-337844.1 11/27/2017
4.6 

8-K001-337844.1 1/23/2018
10.1† 8-K 001-33784 10.8 10/7/2016
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SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
10.1.1† 10-K001-3378410.1.4 3/3/2017
10.1.1.1† 10-Q001-3378410.1.4.111/3/2017
10.1.2† 10-K001-3378410.1.5 3/3/2017
10.1.3† 

10-Q001-3378410.1.6 8/7/2017
10.1.3.1† 

10-Q001-3378410.1.6.111/3/2017
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† * 
10.3.1† 10-K 001-33784 10.3.1 2/27/2015 
10.3.2† 8-K 001-33784 10.1 8/5/2015 
10.3.3† 10-K 001-33784 10.3.2 2/27/2015 
10.3.4† 10-Q 001-33784 10.3.4 11/5/2015 
10.3.5†

8-K001-3378410.1 2/9/2018
10.3.6†8-K001-3378410.1 1/28/2019
10.4† 8-K 001-33784 10.9 10/7/2016  
10.5 8-K 001-33784 10.1 10/7/2016 
119
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
10.6 8-K 001-33784 10.1 2/13/2017 
10.7 10-K001-3378410.6 3/3/2017
10.8 8-K 001-33784 10.4 10/7/2016  
10.9 8-K 001-33784 10.5 10/7/2016 
10.10 8-K 001-33784 10.2 10/7/2016 
10.10.1 10-K001-3378410.9.1 3/3/2017
10.11 8-K 001-33784 10.1 5/16/2016 
10.12 

8-K001-3378410.1 12/28/2017
10.13.1 8-K001-3378410.1 6/19/2018
10.13.2 8-K001-3378410.2 6/19/2018
21.1 * 
23.1 * 
23.2 * 
23.3 * 
23.4 * 
31.1 * 
31.2 * 
120
SandRidge Energy, Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
32.1 * 
99.1 * 
99.2 *
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 

Item 16.  Form 10-K Summary

Not Applicable.
121

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.
By
/s/    PAUL D. MCKINNEY   
Paul D. McKinney,
President and Chief Executive Officer
March 5, 2019

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Michael A. Johnson, Philip T. Warman and Dustin Crawford, 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  TitleDate
/s/ PAUL D. MCKINNEY  
President and Chief Executive Officer
(Principal Executive Officer)
March 5, 2019
Paul D. McKinney
/s/ MICHAEL A. JOHNSON  
Senior Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
March 5, 2019
Michael A. Johnson
/s/ BOB G. ALEXANDER  DirectorMarch 5, 2019
Bob G. Alexander
/s/ SYLVIA K. BARNES  DirectorMarch 5, 2019
Sylvia K. Barnes
/s/ JONATHAN CHRISTODORO  DirectorMarch 5, 2019
Jonathan Christodoro
/s/ JONATHAN FRATES  ChairmanMarch 5, 2019
Jonathan Frates
/s/ WILLIAM M. GRIFFIN, JR.DirectorMarch 5, 2019
William M. Griffin, Jr.
/s/ DAVID J. KORNDERDirectorMarch 5, 2019
David J. Kornder
/s/ JOHN J. LIPINSKIDirectorMarch 5, 2019
John J. Lipinski
/s/ RANDOLPH C. READDirectorMarch 5, 2019
Randolph C. Read

122