10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

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)

Delaware		20-8084793
(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 Class		Name of Each Exchange on Which Registered
Common Stock, $0.001 par value		New York Stock Exchange
	Securities registered pursuant to Section 12(g) of the Act:
	None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ No ¨

Indicate by check mark 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. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  o	Accelerated filer o
Non-accelerated filer þ (Do not check if smaller reporting company)	Smaller reporting company 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 30, 2016 was approximately $13.3 million based on the closing price as quoted on the Pink Sheets. As of February 24, 2017, there were 35,872,778 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s definitive proxy statement for the 2017 Annual Meeting of Stockholders are incorporated by reference in Part III.

SANDRIDGE ENERGY, INC.

2016 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

Item		Page
	PART I
1.	Business	1
1A.	Risk Factors	28
1B.	Unresolved Staff Comments	41
2.	Properties	42
3.	Legal Proceedings	43
4.	Mine Safety Disclosures	44
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45
6.	Selected Financial Data	48
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
7A.	Quantitative and Qualitative Disclosures About Market Risk	70
8.	Financial Statements and Supplementary Data	72
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73
9A.	Controls and Procedures	74
9B.	Other Information	75
	PART III
10.	Directors, Executive Officers and Corporate Governance	76
11.	Executive Compensation	77
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	78
13.	Certain Relationships and Related Transactions and Director Independence	79
14.	Principal Accounting Fees and Services	80
	PART IV
15.	Exhibits and Financial Statement Schedules	81
16.	Form 10-K Summary	82
	Signatures
	Exhibit Index

Certain Defined Terms

References in this report to the “Company,” “SandRidge,” “we,” “our,” and “us” mean SandRidge Energy, Inc., including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary. In addition, this report includes terms commonly used in the oil and natural gas industry, which are defined in the “Glossary of Oil and Natural Gas Terms” beginning on page 23.

Cautionary Note Regarding Forward-Looking Statements

Various statements contained in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning the Company’s capital expenditures, liquidity, capital resources and debt profile, pending dispositions, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the effects thereof on the Company’s financial condition and other statements concerning the Company’s 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. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Company disclaims any obligation to update or revise these forward-looking statements unless required by law, and it cautions readers not to rely on them unduly. While the Company’s management considers 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, including the following:

• risks associated with drilling oil and natural gas wells;

• the volatility of oil, natural gas and natural gas liquids (“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 its 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;

• 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;

• competition in the oil and natural gas industry;

• general economic conditions, either internationally or domestically affecting the areas where we operate;

• costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing and the disposal of produced water; and

• the need to maintain adequate internal control over financial reporting.

PART I

Item 1.        Business

GENERAL

SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent and Rockies regions of the United States. The Company’s Rockies properties were acquired during the fourth quarter of 2015.

As of December 31, 2016, the Company had 3,122 gross (2,310.0 net) producing wells, a substantial portion of which it operates, and approximately 1,364,000 gross (950,000 net) total acres under lease. As of December 31, 2016, the Company had one rig drilling in the Mid-Continent. Total estimated proved reserves as of December 31, 2016 were 163.9 MMBoe, of which approximately 74% were proved developed.

The Company’s principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and the Company’s telephone number is (405) 429-5500. SandRidge makes available free of charge on its website at www.sandridgeenergy.com its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the Securities and Exchange Commission (“SEC”). Any materials that the Company has filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549 or accessed via the SEC’s website address at www.sec.gov. The public may also obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

Reorganization Under Chapter 11 and Emergence from Bankruptcy

On May 16, 2016, the Company and certain of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on September 9, 2016 (as amended, the “Plan”), and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016 (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 - Fresh Start Accounting” to the accompanying consolidated financial statements contained in Item 8, “Financial Statements and Supplementary Data.”

The reorganization under Chapter 11 substantially reduced indebtedness and restructured the Company’s balance sheet. Throughout the course of the Chapter 11 reorganization, we were able to conduct normal business activities and pay associated obligations for the period following the bankruptcy filing and paid certain pre-petition obligations, including employee wages and benefits, goods and services provided by certain vendors, transportation of our production, and royalties and costs incurred on the Company’s behalf by other working interest owners. As a result of the reorganization, we now have an improved capital structure and enhanced financial flexibility.

Fresh Start Accounting

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, fresh start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2016 and related fresh start adjustments are included in the accompanying statement of operations for the period from January 1, 2016 through October 1, 2016 (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 after October 1, 2016 (the “Successor 2016 Period”) will not be 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.

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Board of Directors

Pursuant to the Plan of Reorganization confirmed by the Bankruptcy Court, the post-emergence board of directors is comprised of five directors, including the Company’s Chief Executive Officer, James Bennett, and four non-employee directors, Michael L. Bennett, John V. Genova, William “Bill” M. Griffin, Jr. and David J. Kornder.

Presentation of Royalty Trust Activities

Information presented for the years ended December 31, 2015 and 2014 includes 100% of the interests and activities of the SandRidge Mississippian Trust I (the “Mississippian Trust I”), the SandRidge Permian Trust (the “Permian Trust”) and the SandRidge Mississippian Trust II (the “Mississippian Trust II”) (collectively, 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 (“VIEs”), and a cumulative-effect adjustment was made to equity to remove the effect of any previously recorded non-controlling interest. Prior periods were not restated. For the 2016 periods, we have proportionately consolidated only our share of each Royalty Trust’s assets, liabilities, revenues and expenses.

Post-Emergence Business Strategy

SandRidge’s mission is to create resource value from its oil and natural gas development and production activities in the Mid-Continent and Rockies regions of the United States. In pursuit of its mission, the Company focuses on the following strategies:

Complementary Operating Areas. Our primary areas of operation are the Mid-Continent area of Oklahoma and Kansas and the Niobrara Shale in the Colorado Rockies. In the Mid-Continent, we are able to (i) leverage technical expertise in the interpretation of geological and operational opportunities, (ii) take advantage of investments in infrastructure including electrical infrastructure and saltwater gathering and disposal systems and (iii) opportunistically grow our holdings through acquisitions, farmouts and operations in this area to achieve production and reserve growth. We are developing a proven oil resource play on our Rockies acreage similar to that being developed by industry in Colorado’s DJ Basin, as both areas draw from the oil rich Niobrara Shale. We will continue to apply our core competencies in developing medium depth formations in the Rockies by deploying our expertise in multi-stage fracture stimulation, artificial lift and extended and multi-lateral horizontal wellbore designs. Additionally, as operator of a majority of our wells, we can further apply competitive advantages to deliver strong, sustainable returns.

Preservation of Capital in Depressed Commodity Pricing Environment. During periods of depressed oil and natural gas pricing, such as that which began during the second half of 2014 and continued throughout 2015 and 2016, we have implemented measures to preserve capital and liquidity by decreasing capital expenditures and focusing drilling efforts on locations that make the most effective use of existing infrastructure, and which have a greater certainty of economic returns. We have established a range for our 2017 capital expenditures budget between $210.0 million and $220.0 million, with the substantial majority of the budgeted expenditures being designated for exploration and production activities.

Focus on Cost Efficiency and Capital Allocation. By leveraging our experienced workforce, scalable operational structure and infrastructure systems, we are able to achieve cost efficiencies and sustainable returns in the Mid-Continent and Rockies areas. In the Mid-Continent, we focus on lower-risk, high rate of return and repeatable drilling opportunities with long economic lives. This has resulted in improved economic returns associated with our multi-lateral wellbore designs, completion designs, well site production facilities, pad drilling utilization, vendor contracts and spud-to-spud cycle time, which reduced our cost structure in the Mid-Continent. Further, due to the relatively low pressure and shallow characteristics of the reservoirs we develop, we are able to maintain a low-cost operating structure and manage service costs. We believe similar opportunities also exist in the Rockies, and have been able to utilize certain technologies and experience from our Mid-Continent operations in the development of our Rockies acreage. The ability to drill multiple laterals or extended laterals from a single pad or single vertical wellbore is facilitating the cost-effective development of this oil rich resource play.

Mitigate Commodity Price Risk. As appropriate, we enter into derivative contracts to mitigate a portion of the commodity price volatility inherent in the oil and natural gas industry. This increases the predictability of cash inflows for a portion of future production, lessens funding risks for longer term development plans, and locks in rates of return on our capital projects.

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Maintain Flexibility. We have multi-year inventories of both oil and natural gas drilling locations within our core operating areas, which allows management to efficiently direct capital toward projects with the most attractive returns.

Pursue Opportunistic Acquisitions. We periodically review acquisition targets to complement our existing asset base. Targets are selectively identified based on several factors including relative value, hydrocarbon mix and location, and the relative fit of our core competencies and technical expertise and, when appropriate, seek to acquire them at a discount to other capital allocation opportunities.

Acquisitions and Divestitures

2016 Divestiture and Release from Treating Agreement

On January 21, 2016, we transferred ownership of substantially all of our oil and natural gas properties and midstream assets located in the Piñon field in the West Texas Overthrust (“WTO”) and $11.0 million in cash to a wholly owned subsidiary of Occidental Petroleum Corporation (“Occidental”) and were released from all past, current and future claims and obligations under an existing 30-year treating agreement with Occidental.

The assets of Piñon Gathering Company, LLC (“PGC”), which we acquired in October 2015 as discussed further below, were included in the consideration conveyed to Occidental.

2015 Acquisitions

Piñon Gathering Company, LLC. In October 2015, we acquired the assets of and terminated a gas gathering agreement with PGC for $48.0 million in cash and $78.0 million principal amount of newly issued 8.75% Senior Secured Notes due 2020 (“PGC Senior Secured Notes”). PGC owned approximately 370 miles of gathering lines supporting the natural gas production from the Company's Piñon field in the WTO.

Rockies Properties - North Park Basin. In December 2015, we acquired approximately 135,000 net acres in the North Park Basin, Jackson County, Colorado for approximately $191.1 million in cash, including post-closing adjustments. Also included in the acquisition were working interests in 16 wells previously drilled on the acreage. Additionally, the seller paid us $3.1 million for certain overriding interests retained in the properties.

2014 Divestiture

Sale of Gulf of Mexico and Gulf Coast Properties. On February 25, 2014, we sold certain subsidiaries that owned our Gulf of Mexico and Gulf Coast oil and natural gas properties (collectively, the “Gulf Properties”), to Fieldwood Energy, LLC (“Fieldwood”) for $702.6 million, net of working capital adjustments and post-closing adjustments, and Fieldwood’s assumption of approximately $366.0 million of related asset retirement obligations. We used the proceeds from the sale to fund drilling in the Mid-Continent.

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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, 2016, unless otherwise noted

	Estimated Net Proved Reserves (MMBoe)	Daily Production (MBoe/d)(1)	Reserves/ Production (Years)(2)	Gross Acreage	Net Acreage	Capital Expenditures (In millions) (3)
Area
Mid-Continent	127.8	42.2	8.3	1,185,408	793,471	$	105.6
Rockies	30.2	1.4	59.1	140,216	132,504	87.4
Other	5.9	1.6	10.1	38,785	23,909	—
Total	163.9	45.2	9.9	1,364,409	949,884	$	193.0

____________________

(1) Average daily net production for the month of December 2016.

(2) Estimated net proved reserves as of December 31, 2016 divided by production for the month of December 2016 annualized.

(3) Capital expenditures for the year ended December 31, 2016 on an accrual basis.

Properties

Mid-Continent

We held interests in approximately 1,185,000 gross (793,000 net) leasehold acres located primarily in Oklahoma and Kansas at December 31, 2016. Associated proved reserves at December 31, 2016 totaled 127.8 MMBoe, 87% of which were proved developed reserves, based on estimates prepared by Cawley, Gillespie & Associates, Inc., (“CG&A”) and our internal engineers. Our interests in the Mid-Continent as of December 31, 2016 included 1,972 gross (1,179.5 net) producing wells with an average working interest of 60%. We had one rig operating in the Mid-Continent as of December 31, 2016, which was drilling a horizontal well. We drilled a total of 16 wells in this area during 2016, all of which were horizontal wells.

Mississippian Formation. The Mississippian formation is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and southern Kansas, and is a key 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 lies stratigraphically between various formations of Pennsylvanian age and the Devonian-aged Woodford Shale formation. The Mississippian formation can reach 1,000 feet in gross thickness and have targeted porosity zone(s) ranging between 20 and 150 feet in thickness. At December 31, 2016, we had approximately 1,087,000 gross (736,000 net) acres under lease and 1,471 gross (917.6 net) producing wells in the Mississippian formation.

Other Formations. The Meramec formation, the primary target in the STACK play of Blaine and Kingfisher Counties, is currently being drilled using horizontal well technology in Garfield, Major, Dewey, and Woodward Counties, a play area called the NW STACK. The formation is Mississippian in age, lying above the Osage formation and below Chester (if present) and Pennsylvanian formations. It is composed of interbedded shales, sands, and carbonates. The top of the formation ranges from about 5,800 feet at the northern edge of the basin to greater than 14,000 feet toward the interior of the basin. The thickness of the formation ranges from about 50 feet to over 400 feet across the STACK and NW STACK area. We drilled two wells in this formation during 2016. Of our total Mississippian acreage at December 31, 2016, approximately 105,500 gross (54,100 net) acres were under lease in the Meramec formation.

The Osage formation, also a target in the STACK and NW STACK plays, has been targeted both vertically and horizontally across the Anadarko Basin, with the Sooner Trend being a notable historic play. The formation is Mississippian in age, lying above the Woodford formation and below the Meramec and Pennsylvanian formations. It is composed of low porosity, fractured limestone and chert. The top of the formation ranges from 6,000 feet at the northern edge of the basin to about 12,300 feet toward the interior of the basin, with formation thickness ranging from about 450 to 1,400 feet. We drilled one well in this formation during 2016. Of our total Mississippian acreage at December 31, 2016, approximately 13,200 gross (7,600 net) acres were under lease in the Osage formation.

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

Rockies

Our Rockies properties consisted of approximately 140,000 gross (133,000 net) acres, and 25 gross (25.0 net) producing wells with an average working interest of 100%, at December 31, 2016. Associated proved reserves at December 31, 2016 were approximately 30.2 MMBoe, of which approximately 12.1% were proved developed reserves. The Rockies acreage is located within the Niobrara Shale play. The Niobrara Shale is characterized by numerous stacked pay reservoirs at depths of 5,500 to 9,000 feet with reservoir thickness over 450 feet. We drilled a total of 10 horizontal producing wells in this area during 2016.

Other properties

Our other oil and natural gas properties include properties in the Permian Basin. As of December 31, 2016, our other properties consisted of approximately 39,000 gross (24,000 net) leasehold acres, 1,125 gross (1,105.5 net) producing wells with an average working interest of 98%. Associated proved reserves at December 31, 2016 were 5.9 MMBoe, 100% of which were proved developed reserves. We did not drill any wells in this area during 2016.

Proved Reserves

Preparation ofReserves Estimates

The estimates of oil, natural gas and NGL reserves in this report are based on reserve reports, which were largely prepared by independent petroleum engineers. To achieve reasonable certainty, the Company’s reservoir engineers relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy, before consultation with independent petroleum engineers. Such consultation included review of properties, assumptions and any new data available. The Corporate Reservoir department’s internal reserves estimates and methodologies were compared to those prepared by independent petroleum engineers to test the reserves estimates and conclusions before the reserves estimates were included in this report. The accuracy of the reserve estimates is dependent on many factors, including the following:

• 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 such as the future price of oil and natural gas; 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 the Company’s 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 reservoir engineers continually monitor well performance, making reserves estimate adjustments, as necessary, to ensure the most current information is reflected in reserves estimates. This information used to prepare reserve estimates includes production histories as well as other geologic, economic, ownership and engineering data. The Corporate Reservoir department currently has a total of nine full-time employees, comprised of five degreed engineers and four engineering and business analysts with a minimum of a four-year degree in mathematics, finance or other business or science field.

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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, internal controls within the reserve estimation process include

• the Corporate Reservoir Department follows comprehensive SEC-compliant internal policies to determine and report proved reserves including:

• confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests;

• reviewing and using data provided by other departments within the Company such as Accounting in the estimation process;

• communicating, collaborating, analytical engineering with technical personnel of our business units;

• comparing and reconciling the internally generated reserves estimates to those prepared by third parties.

• reserves estimates are prepared by experienced reservoir engineers or under their direct supervision; and

• no employee’s compensation is 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 a committee of executives, and subsequently obtains approval of all 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 Reservoir Department works closely with its 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 the Company’s total proved reserves prepared by each of the independent petroleum consultants is shown in the table below.

	December 31,
	2016		2015		2014
Cawley, Gillespie & Associates, Inc.	72.0	%	77.7	%	82.4	%
Ryder Scott Company, L.P.	18.4	%	8.5	%	—	%
Netherland, Sewell & Associates, Inc.	3.6	%	3.9	%	3.7	%
Total	94.0	%	90.1	%	86.1	%

The remaining 6.0%, 9.9% and 13.9% of the estimated proved reserves as of December 31, 2016, 2015 and 2014, respectively, were based on internally prepared estimates.

Copies of the reports issued by our independent petroleum consultants with respect to the Company’s oil, natural gas and NGL reserves for the substantial majority of all geographic locations as of December 31, 2016 are filed with this report as Exhibits 99.1, 99.2 and 99.3. The geographic location of the Company’s estimated proved reserves prepared by each of the independent petroleum consultants as of December 31, 2016 is presented below.

	Geographic Locations—by Area by State
Cawley, Gillespie & Associates, Inc.	Mid-Continent—KS, OK
Ryder Scott Company, L.P.	Rockies—CO
Netherland, Sewell & Associates, Inc.	Permian Basin—TX

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

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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 consulting petroleum engineering since 2013 and over 15 years of prior industry experience;

• licensed professional engineers in the state of Texas; and

• Bachelor of Science Degree in Chemical Engineering

Technologies

Under SEC rules, proved reserves are 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, based on prices used to estimate reserves, 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. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

The area of a reservoir considered proved includes (i) the area 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.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. In determining the amount of proved reserves, the price used must be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average

7

of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. See further discussion of prices in “Risk Factors” included in Item 1A of this report.

The estimates of proved developed reserves included in the reserve report were prepared using decline curve analysis to determine the reserves of individual producing wells. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field.

Reporting of Natural Gas Liquids

NGLs are produced as a result of the processing of a portion of our natural gas production stream. At December 31, 2016, NGLs comprised approximately 21% of total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where we have contracts in place for the extraction and separate sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels. 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.

8

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, 2016, 2015 and 2014, the substantial majority of which were prepared by independent petroleum engineers. The PV-10 values shown in the table below are not intended to represent the current market value of estimated proved reserves as of the dates shown. The reserve reports were based on the Company’s drilling schedule at the time year end reserve reports were prepared. Reserves for 2016 include our proportionate share of the reserves attributable to the Royalty Trusts while 2015 and 2014 include 100% of the reserves attributable to the Royalty Trusts. Our year end 2016 PUD development plan established that 100% of our current proved undeveloped reserves will be developed by the end of 2021. See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.

	December 31,
	2016		2015		2014
Estimated Proved Reserves(1)
Developed
Oil (MMBbls)	25.9		48.6		79.0
NGL (MMBbls)	29.3		51.1		56.8
Natural gas (Bcf)	393.0		964.6		1,203.4
Total proved developed (MMBoe)	120.7		260.5		336.4
Undeveloped
Oil (MMBbls)	27.0		29.3		47.0
NGL (MMBbls)	4.2		9.9		35.0
Natural gas (Bcf)	71.8		149.2		584.8
Total proved undeveloped (MMBoe)	43.2		64.1		179.5
Total Proved
Oil (MMBbls)	52.9		77.9		126.0
NGL (MMBbls)	33.5		61.0		91.8
Natural gas (Bcf)	464.8		1,113.8		1,788.2
Total proved (MMBoe)(2)	163.9		324.6		515.9
Standardized Measure of Discounted Net Cash Flows (in millions)(2)(3)	$	438.4	$	1,315.0	$	5,516.4
PV-10 (in millions)(4)	$	438.4	$	1,314.6	$	4,087.8

____________________

(1) Estimated proved reserves and the future net revenues, PV-10 and Standardized Measure were determined using a 12-month unweighted average of the first-day-of-the-month index price for each month of each year, and do not reflect actual prices at December 31, 2016 or current 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 Company’s 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, 2016	$	39.25	$	2.48	$	38.59	$	10.99	$	1.56
December 31, 2015	$	46.79	$	2.59	$	45.29	$	12.68	$	1.87
December 31, 2014	$	91.48	$	4.35	$	91.65	$	32.79	$	3.61

____________________

(a) Index prices are based on average West Texas Intermediate posted 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.

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(2) Estimated total proved reserves and Standardized Measure attributable to noncontrolling interest for the years ended December 31, 2015 and 2014 are shown in the table below.

	Estimated Proved Reserves (MMBoe)	Standardized Measure (In millions)
December 31, 2015	19.1	$	224.6
December 31, 2014	27.6	$	643.3

See “Note 22—Supplemental Information on Oil and Natural Gas Producing Activities” to the consolidated financial statements in Item 8 of this report for additional information regarding reserve and Standardized Measure amounts attributable to noncontrolling interests.

(3) Standardized Measure represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions used to calculate PV-10. Standardized Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes. At December 31, 2016, the present value of future income tax discounted at 10% was insignificant due to an excess of tax basis in the full cost pool over projected undiscounted future cash flows.

(4) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices for the years ended December 31, 2016, 2015 and 2014. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of the Company’s 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,
	2016		2015		2014
	(In millions)
Standardized Measure of Discounted Net Cash Flows	$	438.4	$	1,314.6	$	4,087.8
Present value of future income tax discounted at 10%	—		0.4		1,428.6
PV-10	$	438.4	$	1,315.0	$	5,516.4

Proved Reserves - Mid-Continent. Proved reserves in the Mid-Continent, primarily the Mississippian formation, decreased from 259.1 MMBoe at December 31, 2015 to 127.8 MMBoe at December 31, 2016. Net of production, the overall decrease of 113.2 MMBoe is primarily due to downward revisions of prior estimates of approximately 106.6 MMBoe, predominantly from revisions of approximately 94.5 MMBoe due to well performance and 12.1 MMBoe due to pricing. The negative revisions from well performance 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. The other decrease was 13.0 MMBoe of adjustment due to the proportionate consolidation of the Royalty Trusts’ reserves in 2016 compared to full consolidation in 2015. These decreases were partially offset by 6.5 MMBoe of extensions due to successful drilling.

Proved Reserves - Rockies. Our proved reserves in the Rockies were acquired in December 2015 and increased from 27.6 MMBoe at December 31, 2015 to 30.2 MMBoe at December 31, 2016, primarily due to reserve extensions from horizontal drilling. The acquisition of these reserves in 2015 provided an important proved reserve addition to our asset base. Reservoir characteristics of the Niobrara in the North Park Basin are similar to those of the Niobrara in the DJ Basin to the east of North Park. The Niobrara reservoir consists of multiple stacked benches with the Company’s proved reserves primarily booked to

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only one bench. Proved developed reserves were booked based on 25 horizontal producing wells across the play. Production performance and reservoir data gathered from the producing wells confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. These wells encountered proven Niobrara reserves within multiple benches. Using the performance of the proved developing producing wells, proved undeveloped reserves were booked for only one bench of the Niobrara across 27 sections of the proved development area. Although well density in the DJ Basin Niobrara indicates the potential for greater than four wells per section booking, we have only booked up to four wells per section for the Niobrara.

Proved Reserves - Other.In 2016, proved reserves, net of production, decreased by 31.3 MMBoe, primarily due tothe divestiture of 24.6 MMBoe of reserves located in the Piñon field in the WTO and a decrease of 6.1 MMBoe due to the proportionate consolidation of the Royalty Trusts’ reserves in 2016 compared to full consolidation in 2015. In 2015, proved reserves decreased by 20.0 MMBoe, primarily due to pricing revisions as a result of significantly lower commodity prices.

Proved Undeveloped Reserves. The following table summarizes activity associated with proved undeveloped reserves during the periods presented:

	Year Ended December 31,
	2016		2015		2014
Reserves converted from proved undeveloped to proved developed (MMBoe)	6.8		15.8		31.4
Drilling capital expended to convert proved undeveloped reserves to proved developed reserves (in millions)	$	64.5	$	117.7	$	343.6

Total estimated proved undeveloped reserves as of December 31, 2016 were 43.2 MMBoe, a decrease of 20.9 MMBoe from the prior year, due primarily to downward revisions due to lower prices. Reserves added from extensions and discoveries totaled 5.5 MMBoe, 3.2MMBoe in the Mid-Continent as a result of horizontal drilling and 2.3 MMBoe in the Rockies 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 the year ended December 31, 2015, we recognized a decrease in proved undeveloped reserves of 115 MMBoe, primarily due to negative revisions of approximately 147 MMBoe resulting from lower commodity prices. These negative revisions were partially offset by an addition to oil, natural gas and NGL reserves associated with proved undeveloped properties of 48 MMBoe for the year ended December 31, 2015. Reserves added from extensions and discoveries totaled 22 MMBoe, primarily from horizontal drilling in the Mississippian formation in the Mid-Continent, which includes 6 MMBoe of proved undeveloped reserves booked and converted during 2015. Acquisition of the Rockies assets, located in Jackson County, Colorado, in December 2015 added 26 MMBoe of proved undeveloped reserves. Approximately 10 MMBoe of proved undeveloped reserves at December 31, 2014 were converted to proved developed reserves during 2015.

Excluding asset sales, we recognized a net addition to oil, natural gas and NGL reserves associated with proved undeveloped properties of 73 MMBoe for the year ended December 31, 2014. Reserves added from extensions and discoveries totaled 67 MMBoe, primarily from horizontal drilling in the Mississippian formation in the Mid-Continent, which includes 10 MMBoe of proved undeveloped reserves booked and converted during 2014. Net positive revisions of 6 MMBoe were recognized and were comprised of 16 MMBoe in increases from the Mid-Continent primarily from an improved overall Mississippian proved undeveloped type curve, partially offset by negative 10 MMBoe revisions primarily from the removal of Permian Basin proved undeveloped drilling locations not expected to be drilled within a five year period. Approximately 21 MMBoe of proved undeveloped reserves at December 31, 2013 were converted to proved developed reserves during 2014.

For additional information regarding changes in proved reserves during each of the three years ended December 31, 2016, 2015 and 2014 see “Note 22—Supplemental Information on Oil and Natural Gas Producing Activities” to the consolidated financial statements in Item 8 of this report.

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Significant Fields

Oil, natural gas and NGL production for fields containing more than 15% of the Company’s total proved reserves at each year end are presented in the table below. The Mississippi Lime Horizontal field, contained more than 15% of the Company’s total proved reserves at December 31, 2016, 2015 and 2014, and the Niobrara field contained more than 15% of the Company’s total proved reserves at December 31, 2016.

	Oil (MBbls)	NGL (MBbls)	Natural Gas (MMcf)	Total (MBoe)
Year Ended December 31, 2016
Mississippi Lime Horizontal	5,029	4,357	56,894	18,868
Niobrara	500	—	—	500
Year Ended December 31, 2015
Mississippi Lime Horizontal	8,041	4,785	77,542	25,750
Year Ended December 31, 2014
Mississippi Lime Horizontal	8,234	3,470	65,839	22,677

Mississippi Lime Horizontal Field. The Mississippi Lime Horizontal Field is located on the Anadarko Shelf in northern Oklahoma and Kansas and produces from the Mississippian formation. The Company’s interests in the Mississippi Lime Horizontal Field as of December 31, 2016 included 1,471 gross (917.6 net) producing wells and a 62% average working interest in the producing area.

Niobrara Field. The Niobrara field is located in Colorado and produces from the Niobrara Shale. The Company’s interests in the Niobrara Field as of December 31, 2016 included 25 gross (25.0 net) producing wells and a 100% average working interest in the producing area.

Production and Price History

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

	Successor		Predecessor		Combined		Predecessor
	Period from October 2, 2016 through December 31,		Period from January 1, 2016 through October 1,		Year Ended December 31,		Year Ended December 31,
	2016		2016		2016		2015		2014
Production data (in thousands)
Oil (MBbls)	1,214		4,315		5,529		9,600		10,876
NGL (MBbls)	999		3,358		4,357		5,044		3,794
Natural gas (MMcf)	12,771		44,124		56,895		92,105		85,697
Total volumes (MBoe)	4,342		15,027		19,369		29,995		28,953
Average daily total volumes (MBoe/d)	47.7		54.6		52.9		82.2		79.3
Average prices—as reported(1)
Oil (per Bbl)	$	47.03	$	36.85	$	39.09	$	45.83	$	89.86
NGL (per Bbl)	$	14.77	$	12.67	$	13.15	$	14.36	$	33.41
Natural gas (per Mcf)	$	2.07	$	1.78	$	1.84	$	2.12	$	3.70
Total (per Boe)	$	22.64	$	18.63	$	19.53	$	23.59	$	49.08

__________________

(1) Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.

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	Successor		Predecessor
	Period from October 2, 2016 through December 31,		Period from January 1, 2016 through October 1,		Year Ended December 31,
	2016		2016		2015		2014
Expenses per Boe
Lease operating expenses
Transportation(1)	$	—	$	1.75	$	1.51	$	1.23
Processing, treating and gathering	0.02		0.03		0.88		1.16
Other lease operating expenses(2)	5.67		6.71		7.67		9.27
Total lease operating expenses	$	5.69	$	8.49	$	10.06	$	11.66
Production taxes(3)	$	0.61	$	0.41	$	0.51	$	1.10
Ad valorem taxes	$	0.07	$	0.14	$	0.23	$	0.29

____________________

(1) The Successor Company transportation costs are presented as a deduction from revenues. See “Note 3 - Summary of Significant Accounting Policies” to the accompanying consolidated financial statements.

(2) The years ended December 31, 2015 and 2014 include $34.9 million and $33.9 million, respectively, for amounts related to shortfalls in meeting annual CO₂ delivery obligations under a CO₂ treating agreement as described under “—2016 Divestiture and Release from Treating Agreement” above.

(3) Net of severance tax refunds.

Productive Wells

The following table sets forth the number of productive wells in which the Company owned a working interest at December 31, 2016. 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 the Company has a working interest and net wells are the sum of the fractional working interests owned in gross wells.

	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Area
Mid-Continent	1,667	1,032.6	305	146.9	1,972	1,179.5
Rockies	25	25.0	—	—	25	25.0
Other	1,125	1,105.5	—	—	1,125	1,105.5
Total	2,817	2,163.1	305	146.9	3,122	2,310.0

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Drilling Activity

The following table sets forth information with respect to wells completed during the periods indicated. The information presented 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. Gross wells refer to the total number of wells in which the Company had a working interest and net wells are the sum of fractional working interests owned in gross wells. As of December 31, 2016, we had 2 gross (1.8 net) operated wells drilling, completing or awaiting completion.

	2016						2015						2014
	Gross	Percent		Net	Percent		Gross	Percent		Net	Percent		Gross	Percent		Net	Percent
Completed Wells
Development
Productive	32	100.0	%	27.0	100.0	%	167	100.0	%	117.0	100.0	%	626	97.5	%	482.3	97.4	%
Dry	—	—	%	—	—	%	—	—	%	—	—	%	16	2.5	%	13.0	2.6	%
Total	32	100.0	%	27.0	100.0	%	167	100.0	%	117.0	100.0	%	642	100.0	%	495.3	100.0	%
Exploratory
Productive	—	—	%	—	—	%	9	100.0	%	7.0	100.0	%	6	60.0	%	4.6	60.5	%
Dry	—	—	%	—	—	%	—	—	%	—	—	%	4	40.0	%	3.0	39.5	%
Total	—	—	%	—	—	%	9	100.0	%	7.0	100.0	%	10	100.0	%	7.6	100.0	%
Total
Productive	32	100.0	%	27.0	100.0	%	176	100.0	%	124.0	100.0	%	632	96.9	%	486.9	96.8	%
Dry	—	—	%	—	—	%	—	—	%	—	—	%	20	3.1	%	16.0	3.2	%
Total	32	100.0	%	27.0	100.0	%	176	100.0	%	124.0	100.0	%	652	100.0	%	502.9	100.0	%

The Company had one third-party rig operating on its Mid-Continent acreage, and no other rigs operating on its other acreage as of December 31, 2016.

Developed and Undeveloped Acreage

The following table sets forth information regarding the Company’s developed and undeveloped acreage at December 31, 2016:

	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
Area
Mid-Continent	629,965	410,000	555,443	383,471
Rockies	16,366	16,412	123,850	116,092
Other	17,944	14,956	20,841	8,953
Total	664,275	441,368	700,134	508,516

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Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. As of December 31, 2016, the gross and net acres subject to leases in the undeveloped acreage summarized in the above table are set to expire as follows:

	Acres Expiring
	Gross	Net
Twelve Months Ending
December 31, 2017	428,349	315,326
December 31, 2018	68,783	43,906
December 31, 2019	37,473	24,505
December 31, 2020 and later	8,161	5,776
Other(1)	157,368	119,003
Total	700,134	508,516

____________________

(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, 2017, includes approximately 369,227 gross (269,130 net) acres in the Mid-Continent area and 48,548 gross (46,099 net) acres in the Rockies area. Of the total 2017 expiring acreage, we anticipate 194,096 gross (130,288 net) acres in the Mid-Continent and 37,925 gross (37,925 net) acres in the Rockies will not be extended or held by production. Approximately 86% of the expiring acreage falls outside of the Company’s core development areas. The core development areas include the NW STACK, the Rockies, and high-graded portions of the Mississippian formation.

Marketing and Customers

We sell our oil, natural gas and NGLs to a variety of customers, including utilities, oil and natural gas companies and trading and energy marketing companies. We had two customers that individually accounted for more than 10% of our total revenue during the Successor 2016 Period and the Predecessor 2016 Period. See “Note 3—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 for our production makes it unlikely that the loss of a single customer in the areas in which we sell our production would materially affect our sales. We do not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements.

Title to Properties

As is customary in the oil and natural gas industry, we conduct an initial preliminary review of the title to our properties which do not have proved reserves. Prior to commencing drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. In addition, prior to completing an acquisition of producing oil and natural gas leases, 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

The Company competes 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. The Company believes that its leasehold acreage position, geographic concentration of operations and technical and operational capabilities enable it 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

15

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.

SEASONAL NATURE OF BUSINESS

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase 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 its operating areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives, can delay the installation of production facilities, and can increase competition for equipment, supplies and personnel during certain times of the year, which could lead to shortages and increase costs or delay operations.

ENVIRONMENTAL REGULATIONS

General

Our oil and natural gas exploration, development and production operations are subject to stringent and complex federal, state, tribal, regional and local laws and regulations governing worker safety and health, the discharge and disposal of materials into the environment, environmental protection, and natural resources. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state and local agencies, (and, in some cases, private individuals) have the power to enforce compliance with these laws and regulations and the permits issued under them. These laws and regulations may, among other things: (i) require permits to conduct exploration, drilling, water withdrawal and other production 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 affect 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 the Company 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 treatment and disposal or release of hazardous substances, hydrocarbons, and wastes

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were not under our control. These properties and the substances or wastes disposed 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 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 solid wastes under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous solid waste requirements. However, it is possible that these wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. 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 Clean Air Act, 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 is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017. 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. In June 2016, the EPA also issued final rules that require the reduction of volatile organic compound and methane emissions from additional new, modified or reconstructed oil and natural gas emissions sources. Compliance with these and

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other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant.

Water Discharges

The federal Water Pollution Control Act, 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 as well as state waters. 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 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 to waters of the United States and state waters 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, but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts consider lawsuits opposing implementation of the rule. To the extent the rule expands the scope of the CWA’s jurisdiction, we could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly-owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.

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

Subsurface Injections

Underground injection operations performed by us are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although the Company monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property damages and personal injuries. Additionally, some states have considered laws mandating the recycling of flowback and produced water. If such laws are adopted in areas where we conduct operations, our operating costs may increase significantly.

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical

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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, on February 16, 2016, the OCC issued a plan to reduce disposal well volume in the Arbuckle formation by 40 percent, covering approximately 5,281 square miles and 245 disposal wells injecting wastewater into the Arbuckle formation. In the plan, the OCC identified 76 SandRidge 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. On March 7, 2016, the OCC reduced the injection volume of additional Arbuckle disposal wells, including wells we operate. Following earthquakes in August, September and November, the OCC and EPA further limited the disposal volumes that can be disposed in Arbuckle wells, although these recent actions did not cover our disposal wells.

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 identified five areas of heightened seismic concern in Harper and Sumner Counties and created a timeframe over which the maximum of 8,000 barrels of saltwater injection daily into each well. SandRidge and other operators of injection wells were required to reduce the injection volume, and any injection well drilled deeper than the Arbuckle Formation was required to be plugged back to a shallower formation in a manner approved by the Kansas Corporation Commission. In August 2016, the Kansas Corporation Commission issued an order that put a 16,000 barrels per day limit on additional Arbuckle disposal wells not previously identified in the order released in March 2015.

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 has published its findings that emissions of carbon dioxide (“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 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, and blowdowns of natural gas transmission pipelines. The EPA has also adopted regulations that seek to reduce GHG emissions from certain sources. For example, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector. 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. Future implementation of the BLM rule is uncertain. However, both the EPA and BLM methane rules impose leak detection and repair (“LDAR”) requirements. 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 is one of almost 200 nations that

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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 and future participation in the Paris Agreement is uncertain. The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur additional costs 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. 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. 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. If endangered or otherwise protected species are located in areas where we wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. On February 11, 2016, the U.S. Fish and Wildlife Service published a final policy which alters how it identifies critical habitat for endangered and threatened species. 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, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service (the “FWS”) is required to consider listing numerous species as endangered under the ESA by the end of the agency’s 2017 fiscal year.

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

We are an active participant on various agency and industry committees that are developing or addressing various EPA 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 that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided 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 believe we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

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

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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.

Hydraulic Fracturing

Hydraulic fracturing is a practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. Oil and natural gas may be recovered from certain of our oil and natural gas properties through the use of hydraulic fracturing, combined with sophisticated drilling. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted federal regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAA final regulations in 2012 and additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry; issued in June 2016 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; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, 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 ruling is currently on appeal before the U.S. Tenth Circuit Court of Appeals.

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. At the state level, some states, including Oklahoma, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure, 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.

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OTHER REGULATION OF THE OIL AND NATURAL GAS INDUSTRY

The oil and natural gas industry is extensively regulated by numerous federal, state, local, and regional authorities, as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases the Company’s cost of doing business and, consequently, affects its profitability, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The 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.

In July 2014, the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) released the details of a comprehensive rulemaking proposal to improve the safe transportation of large quantities of flammable materials by rail, particularly crude oil and ethanol. The Federal Railroad Administration and PHMSA jointly published the final rule on May 1, 2015, and it became effective July 7, 2015.  The final rule (i) contains a new enhanced tank car standard and a risk-based retrofitting schedule for older tank cars carrying crude oil and ethanol; (ii) requires a new braking standard for certain trains; (iii) designates new operational protocols for trains transporting large volumes of flammable liquids, such as routing requirements, speed restrictions, and information for local government agencies; and (iv) provides new sampling and testing requirements to improve classification of energy products placed into transport.

Sales of oil, natural gas and NGLs are 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 NGLs 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

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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 United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

Natural Gas Sales and Transportation

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 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we 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.

EMPLOYEES

We completed reductions in force during the first and fourth quarters of 2016, and as of December 31, 2016, had 509 full-time employees, including 110 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of our 509 employees, 278 were located at the Company’s headquarters in Oklahoma City, Oklahoma at December 31, 2016, and the remaining employees worked in our various field offices and drilling sites.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of certain oil and natural gas industry 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.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.

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Bcf. Billion cubic feet of natural gas.

Bench. A geological horizon; a thin, 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 2016 of $39.25/Bbl for oil and $2.48/Mcf for natural gas, the ratio of economic value of oil to gas was approximately 16 to 1, even though the ratio for determining energy equivalency is 6 to 1.

Boe/d. Boe per day.

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

Completion. The process of treating a drilled well 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.

CO₂. Carbon dioxide.

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 and to 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 and equip 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.

Environmental Assessment (“EA”). A study to determine whether an action significantly affects the environment, which federal or state agencies may be required by the National Environmental Policy Act or similar state statutes to undertake prior to the commencement of activities that would constitute federal or state actions, such as permitting oil and natural gas exploration and production activities.

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.

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

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

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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.

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

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

NYMEX. The New York Mercantile Exchange.

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

Present value of future net revenues. The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10% 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. Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which defines proved reserves as:

Those quantities of oil and natural gas 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.

The area of a reservoir considered proved includes (i) the area 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 or gas 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.

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Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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 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.

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.

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 recompletion.

(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.

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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.

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Item 1A.    Risk Factors

The Chapter 11 proceedings may have disrupted our business and may have materially and adversely affected our operations.

We have attempted to minimize the adverse effect of our Chapter 11 reorganization on our relationships with our employees, suppliers, customers and other parties. Nonetheless, our relationships with our customers, suppliers, certain liquidity providers and employees may have been adversely impacted and our operations, currently and going forward, could be materially and adversely affected.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan of Reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we adopted fresh-start accounting effective on October 1, 2016 in accordance with ASC Topic 852, “Reorganizations.”  Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in our historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

Our historical financial information may not be indicative of future financial performance.

Our capital structure was significantly impacted by the Plan of Reorganization. Under fresh-start reporting rules that apply 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 apply, 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.

Upon our emergence from bankruptcy, the composition of our board of directors changed significantly, and the transition to a new board of directors will be critical to our success.

Pursuant to the Plan, the composition of our board of directors changed significantly. Currently, the board of directors is made up of five directors, only one of which previously served on our board of directors. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the board of directors and, thus, may have different views on the issues that will determine the future of the Company. As a result, our future strategy and plans may differ materially from those of the past.

Additionally, the ability of our new directors to quickly expand their knowledge of our business plans, operations and strategies and our technologies will be critical to their ability to make informed decisions about our strategy and operations, particularly given the competitive environment in which our business operates. If our board of directors is not sufficiently informed to make such decisions, our ability to compete effectively and profitably could be adversely affected.

The exercise of all or any number of outstanding Warrants or the issuance of stock-based awards may dilute your holding of shares of our common stock.

As of the date of filing this report, we have outstanding Warrants (as defined in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview”) to purchase approximately 6.4 million shares of our common stock. In addition, we have as of the date of this report, 3.2 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

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any such options or the Warrants, could have an adverse effect on the market for our common stock, including the price that an investor could obtain for their shares. Investors may experience dilution in the net tangible book value of their investment upon the exercise of the Warrants and any stock options that may be granted or issued pursuant to the Omnibus Incentive Plan in the future.

We do not expect to pay dividends in the near future.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. 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.

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 for hydraulic fracturing operations;

• equipment malfunctions, failures or accidents;

• lack of available gathering facilities or delays in construction of gathering 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;

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• 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 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.

Oil, natural gas and NGL prices can fluctuate widely due to a number of factors that are beyond our control. Continued depressed or further declining 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 realizes from the sale of oil, natural gas and NGLs. The markets for these commodities are very volatile and experienced significant decline during the latter half of 2014, and remained depressed throughout 2015 and 2016. Oil, natural gas and NGL prices 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.

For oil, from January 2012 through December 2016, the highest month end NYMEX settled price was $107.65 per Bbl and the lowest was $33.62 per Bbl. For natural gas, from January 2012 through December 2016, the highest month end NYMEX settled price was $5.56 per MMBtu and the lowest was $1.71 per MMBtu. In addition, the market price of oil and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil and natural gas for heating purposes during the winter season.

Oil prices dropped sharply during the latter half of 2014 and remained at lower levels throughout 2015 and 2016, settling as low as $26.21 per Bbl in February 2016. If a buildup in inventories, lower global demand, or other factors cause prices for U.S. oil, natural gas and NGLs to weaken, our cash flows and revenues may be negatively affected, and we also may ultimately reduce the amount of oil, natural gas and NGLs we can produce economically, causing us to make substantial downward adjustments to its estimated proved reserves and having a material adverse effect on our financial condition and results of operations.

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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 its cash flow and income, are highly dependent on our success in efficiently developing and exploiting its current 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 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.

Our identified drilling locations are scheduled 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 that would be necessary to drill such locations.

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 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. 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 must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in 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 typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres, or the leases are renewed. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Unless we 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.

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 most recent 12-month average prices for oil and natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges. The Successor Company and Predecessor Company incurred full cost ceiling impairment charges of $319.1 million and $657.4 million for the Successor 2016 Period and the Predecessor 2016 Period, respectively, and the Predecessor Company had cumulative full cost ceiling impairment charges of $8.8 billion and $8.2 billion at October 1, 2016 and December 31, 2015, respectively. We incurred full cost ceiling impairment charges of $4.5 billion and $164.8 million for the years ended December 31, 2015, and 2014, respectively. If oil, natural gas and NGL 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 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 present value of future net cash flows from our proved reserves calculated in accordance with SEC guidelinesare 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. Commodity prices have remained depressed and have at times trended lower. Accordingly, if we had prepared our December 31, 2016 reserve reports based on the updated 12-month average index prices (which were $42.50 and $2.66 through February 1, 2017) instead of the 12-month average index prices (which were $39.25 and $2.48), and without regard to additions or other further revisions to reserves other than as a result of such pricing changes, the PV-10 value of our internally estimated proved reserves would have increased. 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 its incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, we use a 10% discount factor when calculating discounted future net cash flows, which may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

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 2016, we completed a total of 32 gross wells, none of which were identified as dry wells. If we drill additional wells that we identify as dry wells in our current and future prospects, our drilling success rate may decline and materially harm our business.

Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather.

Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather. Repercussions of natural disasters or severe weather conditions may include:

• evacuation of personnel and curtailment of operations;

• damage to drilling rigs or other facilities, resulting in suspension of operations;

• inability to deliver materials to worksites; and

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• 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, 2016, approximately 26.4% 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, 2016, approximately 78.0% of our proved reserves and approximately 93.6% 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 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.

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Our development and exploration operations require substantial capital, and 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 $65.6 million for the Successor 2016 Period and had cash flow used in operations was $112.1 million for the Predecessor 2016 Period. Cash flow from operations was $373.5 million and $621.1 million, for the years ended December 31, 2015 and 2014, respectively. However, as a result of sustained depressed commodity prices, the capital markets that we have historically accessed have recently been and may continue to be constrained to such an extent that debt or equity capital raises are practically unfeasible. If the debt and equity capital markets do not improve, 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.

Reductions in our revenues and cash flow from operations, whether as a result of lower oil, natural gas and NGL prices, lower production, declines in reserves or for any other reason, may limit our ability to obtain the capital necessary to sustain its operations at desired levels. In order to fund capital expenditures, we may seek additional financing.

Disruptions in the global financial and capital markets also could 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.

The agreements governing our existing indebtedness have restrictions, financial covenants and borrowing base redeterminations, which could adversely affect our operations.

The agreements governing our senior credit facility dated February 10, 2017, (the “refinanced 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 refinanced credit facility also requires us to comply with certain financial covenants and ratios. See additional discussion of the refinanced credit facility under “Cash Flows-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 refinanced credit facility. Our failure to comply with any of the restrictions and covenants under the refinanced 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 refinanced 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 refinanced 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

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of the refinanced credit facility is incurred. If any future indebtedness under our refinanced credit facility were to be accelerated, our assets may not be sufficient to repay such indebtedness in full.

The Bankruptcy Court’s order confirming the Plan is subject to a pending appeal.

Parties have appealed the Bankruptcy Court’s decision confirming the Plan. Specifically, on September 23, 2016, an informal group of our former shareholders appealed the Bankruptcy Court’s entry of the Amended Order Confirming the Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc. and its Debtor Affiliates (Docket No. 901). We cannot predict with certainty the ultimate outcome of such appeal. An adverse outcome could negatively affect our business, operations, or finances.

Our derivative activities could result in financial losses and reduce earnings.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently have entered, and may in the future enter, into derivative contracts for a portion of our future oil and natural gas production, including fixed price swaps, collars and basis swaps. We have not designated and do not 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. Derivative contracts also expose us to the risk of financial loss in some circumstances, including when:

• production is less than expected;

• the counterparty to the derivative contract defaults on its contract obligations; or

• the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.

In addition, these types of derivative contracts can limit the benefit we would receive from increases in the prices for oil and natural gas.

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.

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

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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.

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 for it 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 attempt to benefit from those expenditures.

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 well as 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 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. For example, Congress

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has recently considered, and may continue to consider, legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, and the elimination of certain U.S. federal tax preferences available with respect to oil and natural gas exploration and production activities. 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.

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 materials 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. Increased scrutiny of the oil and natural gas industry may occur as a result of the EPA’s FY 2017-2019 National Enforcement Initiatives, through which the EPA will purportedly address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.

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 additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry; issued in June 2016 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; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, 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 ruling is currently on appeal before the U.S. Tenth Circuit Court of Appeals.

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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. In addition, certain states, including Oklahoma, have adopted regulations that could impose new or more stringent permitting, disclosure, and well-construction requirements on hydraulic fracturing operations. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted at the local, state or federal level, fracturing activities with respect to our properties could become subject to additional permit requirements, reporting requirements or operational restrictions, which may result in permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. 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 Part I, Item 1 of this report for additional discussion of the current and potential impacts of legislation or regulatory initiatives related to seismic activity on the Company.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that the Company produces.

The EPA has 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. In additon, 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. Future implementation of the BLM rule is uncertain. However, both the EPA and BLM methane rules impose LDAR requirements. 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 is one of almost 200 nations that agreed in December 2015 to the Paris Agreement. However, the Paris Agreement does not impose any binding obligations on the United States and future participation in the Paris Agreement is uncertain. It is not possible at this time to predict how or when the United State might impose restrictions on GHGs as a result of the international agreement agreed to in Paris. 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. 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.

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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 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, 2016, as further described in “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.

Certain U.S. federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated as a result of future legislation.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on the Company’s financial position, results of operations and cash flows.

New derivatives legislation and regulation could adversely affect our ability to hedge risks associated with its business.

The Dodd-Frank Act created a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission (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

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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 its cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations. At this time, the impact of such regulations is not clear.

The future of the CFTC's rulemaking remains uncertain under the new presidential administration. Recent rule proposals by the CFTC suggest that final consideration of major proposed rules will be made by the new 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. In December 2016, the Chairman of the CFTC stated that the CFTC decided to re-propose, rather than finalize, the above regulations, in part based on the uncertainty over the next presidential administration. It is also uncertain whether the current Chairman of the CFTC and other CFTC staff will remain with the CFTC under the new presidential administration. The current Chairman's term expires in April 2017, and two seats are currently open for new appointees, leaving the CFTC's future rulemaking unclear.

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.

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Item 1B.    Unresolved Staff Comments

None.

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Item 2.        Properties

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

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Item 3.        Legal Proceedings

The Plan in the Chapter 11 Cases discharged certain claims, including claims related to litigation proceedings against the Company that arose before the Emergence Date. The Plan generally treated such claims as general unsecured claims that will receive only partial distribution of the amounts of consideration set aside for such claims under the Plan, which consists of cash, shares of New Common Stock and warrants, once their amounts, if any, are finally determined by the Bankruptcy Court or otherwise. The effectiveness of the Plan also resulted in the release of certain claims held by the Company against various parties to the restructuring and related parties, including certain of the Company’s current and former officers and former directors. See “Note 1- Voluntary Reorganization under Chapter 11 Proceedings” to the accompanying consolidated financial statements in Item 8 of this report for further discussion about the Company’s Bankruptcy Petitions and the Chapter 11 Cases.

To the extent that a claim related to a pre-petition proceeding or action is not characterized as a pre-petition general unsecured claim, the Company does not believe that such claim would be material, although the anticipated resolution of any such proceeding or action is inherently unpredictable.

As previously disclosed, on February 4, 2015, the staff of the SEC Enforcement Division in Washington, D.C., notified the Company that it had commenced an informal inquiry concerning the Company’s accounting for, and disclosure of, its CO₂ delivery shortfall penalties under the terms of the Gas Treating and CO₂ Delivery Agreement, dated June 29, 2008, between SandRidge Exploration and Production, LLC, and Oxy USA Inc. Additionally, the Company received a letter from an attorney for a former employee at the Company (the “Former Employee”). In the letter, the attorney alleged, among other things, that the Former Employee had been terminated because he had objected to the levels of oil and gas reserves disclosed by the Company in its public filings. Over 85% of such reserves were calculated by an independent petroleum engineering firm. The Audit Committee of the Company’s pre-emergence Board of Directors retained an independent law firm to review the Former Employee’s allegations and the circumstances of the Former Employee’s termination. In addition, the Company reported the Former Employee’s allegations to the SEC staff, which thereafter issued two subpoenas to the Company relating to the Former Employee’s allegations. Counsel for the Audit Committee responded to both of these subpoenas. During the course of the above inquiries, the SEC issued a subpoena to the Company seeking documents relating to employment-related agreements between the Company and certain employees. The Company cooperated with this inquiry and, after discussion with the staff, the Company sent corrective letters to certain current and former employees who had entered into agreements containing language that may have been inconsistent with SEC rules prohibiting a company from impeding an individual from communicating directly with the SEC about possible securities law violations. The Company also updated its Code of Conduct and other relevant policies.

On June 16, 2016, the SEC filed a proof of claim in the Company’s Chapter 11 Cases in the amount of $1.2 million relating to the SEC staff’s inquiry concerning employment-related agreements. As a result of the SEC’s proof of claim, the Company established a $1.4 million reserve for this matter.

On December 20, 2016, the Company and the SEC settled both the inquiry involving employment-related agreements and the inquiry involving the termination of the Former Employee. Pursuant to the settlement agreement, the Company agreed to pay a fine in the amount of $1.4 million. The fine will be treated as a general unsecured claim under the Plan and, as such, the Company expects to pay approximately $0.1 million to resolve these two inquiries. The Company neither admitted nor denied any violations as part of the settlement agreement. Additionally, the SEC informed the Company that as part of the settlement agreement, the SEC would not be recommending charges against the Company with regard to its pre-petition disclosures of the CO₂ delivery shortfall penalties under the Company’s agreement with Oxy USA Inc., or with regard to the Company’s pre-petition processes and disclosures related to its reserves.

On October 14, 2016, Lisa West and Stormy Hopson filed a class action complaint in the United States District Court for the Western District of Oklahoma against SandRidge Exploration and Production, LLC, among other defendants. In their complaint, plaintiffs assert various tort claims seeking relief for damages allegedly incurred by the plaintiffs and the proposed class for injury to property and for the purchase of insurance policies allegedly needed by the plaintiffs and the proposed class for seismic activity allegedly caused by the defendants’ operation of wastewater disposal wells. An estimate of reasonably probable losses associated with this action cannot be made at this time. The Company had not established any reserves relating to this action.

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.

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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

From October 4, 2016 through December 31, 2016, the Successor Company’s common stock was 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 was also listed on the NYSE under the symbol “SD.” 

The range of high and low sales prices for the Successor Company’s and the Predecessor Company’s respective common stock for the periods indicated, as reported by the NYSE and the Pink Sheets quotations system, is as follows:

	High		Low
2016
Successor Company
Fourth Quarter (from October 4, 2016 through December 31, 2016)	$	26.85	$	15.75
Predecessor Company
Fourth Quarter (through October 3, 2016)	$	0.02	$	0.01
Third Quarter	$	0.06	$	—
Second Quarter	$	0.11	$	0.01
First Quarter	$	0.20	$	0.03
2015
Fourth Quarter	$	0.56	$	0.17
Third Quarter	$	0.90	$	0.25
Second Quarter	$	2.30	$	0.81
First Quarter	$	2.53	$	1.13

On February 24, 2017, there were 2 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 on our common stock 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 to our common stock holders. If our dividend policy were to change in the future, our ability to pay dividends would be subject to these restrictions and the Company’s then-existing conditions, including results of operations, financial condition, contractual obligations, capital requirements, business prospects and other factors deemed relevant by the Successor Company’s board of directors.

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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, 2016. 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.

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, 2012 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, 2012.

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.

46

ISSUER PURCHASES OF EQUITY SECURITIES

The following table presents a summary of share repurchases made by the Successor Company during the three-month period ended December 31, 2016.

	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum  Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (In millions)
Period
October 1, 2016 — October 31, 2016	—	$	—	N/A	N/A
November 1, 2016 — November 30, 2016	—	$	—	N/A	N/A
December 1, 2016 — December 31, 2016	4,647	$	23.72	N/A	N/A
Total	4,647			—

____________________

(1) Includes shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards. Shares withheld are initially recorded as treasury shares, then immediately retired.

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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.

	Successor			Predecessor
	Period from October 2, 2016 through December 31,			Period from January 1, 2016 through October 1,			Year Ended December 31,
	2016			2016			2015			2014			2013			2012
Statement of Operations Data (in thousands, except per share data)
Revenues	$	98,456		$	293,809		$	768,709		$	1,558,758		$	1,983,388		$	1,934,642
Total operating expenses(1)	434,801			1,200,012			5,411,387			968,534			2,152,389			1,609,446
(Loss) income from operations	(336,345		)	(906,203		)	(4,642,678		)	590,224			(169,001		)	325,196
Other (expense) income
Interest expense	(372		)	(126,099		)	(321,421		)	(244,109		)	(270,234		)	(303,349		)
Bargain purchase gain	—			—			—			—			—			122,696
Gain (loss) on extinguishment of debt	—			41,179			641,131			—			(82,005		)	(3,075		)
Reorganization items	—			2,430,599			—			—			—			—
Other income, net	2,744			1,332			2,040			3,490			12,445			4,741
Total other expense	2,372			2,347,011			321,750			(240,619		)	(339,794		)	(178,987		)
(Loss) income before income taxes	(333,973		)	1,440,808			(4,320,928		)	349,605			(508,795		)	146,209
Income tax expense (benefit)	9			11			123			(2,293		)	5,684			(100,362		)
Net (loss) income	(333,982		)	1,440,797			(4,321,051		)	351,898			(514,479		)	246,571
Less: net (loss) income attributable to noncontrolling interest	—			—			(623,506		)	98,613			39,410			105,000
Net (loss) income attributable to SandRidge Energy, Inc.	(333,982		)	1,440,797			(3,697,545		)	253,285			(553,889		)	141,571
Preferred stock dividends	—			16,321			37,950			50,025			55,525			55,525
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(333,982	)	$	1,424,476		$	(3,735,495	)	$	203,260		$	(609,414	)	$	86,046
(Loss) earnings per share
Basic	$	(17.61	)	$	2.01		$	(7.16	)	$	0.42		$	(1.27	)	$	0.19
Diluted	$	(17.61	)	$	2.01		$	(7.16	)	$	0.42		$	(1.27	)	$	0.19

____________________

(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, 2013 or 2012.

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	Successor		Predecessor
	As of December 31,		As of December 31,
	2016		2015			2014		2013		2012
Balance Sheet Data (in thousands)
Cash and cash equivalents	$	121,231	$	435,588		$	181,253	$	814,663	$	309,766
Property, plant and equipment, net	$	817,932	$	2,234,702		$	6,215,057	$	6,307,675	$	8,479,977
Total assets(1)	$	1,081,392	$	2,922,027		$	7,211,823	$	7,630,307	$	9,716,787
Total debt(1)	$	305,308	$	3,562,378		$	3,148,034	$	3,140,419	$	4,227,139
Total stockholders’ equity (deficit)	$	512,917	$	(1,187,733	)	$	3,209,820	$	3,175,627	$	3,862,455
Total liabilities and stockholders’ equity (deficit)	$	1,081,392	$	2,922,027		$	7,211,823	$	7,630,307	$	9,716,787

____________________

(1) Reflects the reclassification of certain debt issuance costs from other assets to long-term debt of $69.1 million, $47.4 million, $54.5 million and $73.9 million for the years ended December 31, 2015, 2014, 2013 and 2012, respectively, as a result of the retrospective adoption of ASU 2015-03 on January 1, 2016. See “Note 3 - Accounting Policies and Procedures” included in Item 8 of this report for further discussion.

There have been no cash dividends declared or paid on either the Predecessor or Successor Company’s common stock.

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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

Basis of Presentation

In accordance with ASC 852, the reorganization value of the Successor Company was allocated to its individual assets based on their estimated fair values as of the Emergence Date. As a result, the consolidated financial statements of the Predecessor Company are not comparable to those of the Successor Company.

Our reorganization under Chapter 11 did not result in 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 by the reorganization, 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 prior 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.

The combined results of operations for the year ended December 31, 2016, represent a supplemental pro forma financial measure due to our reorganization and the application of fresh start accounting. The following line items in our consolidated statements of operations for the year and quarter ended December 31, 2016, are not comparable to any prior annual or quarterly periods due to our reorganization and application of fresh-start accounting:

• Depreciation, depletion and amortization

• Accretion of asset retirement obligations

• Impairment

• Interest Expense

• Net (loss) income

Presentation of Royalty Trust Activities. We adopted the provisions of ASU 2015-02 “Amendments to the Consolidation Analysis,” effective January 1, 2016, which resulted in the determination that the Royalty Trusts no longer qualify as VIEs. As a result, the activities of the Royalty Trusts have been proportionately consolidated for the Predecessor 2016 Period and the Successor 2016 Period. Under the proportionate consolidation method, only our share of each Royalty Trust’s asset, liabilities, revenues and expenses are recorded within the appropriate classifications in the accompanying consolidated financial statements. We adopted the provisions of ASU 2015-02 by recording a cumulative-effect adjustment to equity as of January 1, 2016. As such, the financial information presented for the years ended December 31, 2015 and 2014 has not been restated and includes 100% of the activities of the Royalty Trusts. The portion of each Royalty Trust’s activities attributable to third-party ownership interests is presented as noncontrolling interest for the years ended December 31, 2015 and 2014.

Emergence from Voluntary Reorganization Under Chapter 11

In accordance with the Plan, the following significant transactions occurred upon our emergence from Chapter 11:

• First Lien Credit Agreement.All outstanding obligations under the senior secured revolving credit facility (the “senior credit facility”) were canceled, and claims under the senior credit facility received their proportionate share of (a) $35.0

50

million in cash and (b)  newly established $425.0 million reserve-based revolving credit facility (the “New First Lien Exit Facility”). The New First Lien Exit Facility was subsequently refinanced in February 2017 as discussed in “Liquidity and Capital Resources.”

• Cash Collateral Account. We deposited $50.0 million of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i) $12.5 million will be released to us upon delivery of an acceptable business plan to the administrative agent, (ii) $12.5 million will be released to us upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to us, up to $25.0 million will be released to us upon meeting a minimum 2.00:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017. The $50.0 million cash collateral account was subsequently released to us in February 2017 in conjunction with the refinancing of the New First Lien Exit Facility as discussed in “Liquidity and Capital Resources.”

• 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 the Successor Company’s Common Stock, (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal value of New Convertible Notes, which are mandatorily convertible into approximately 15.0 million shares of New Common Stock upon the first to occur of several triggering events, one of which was the refinancing of the First Lien Exit Facility.

• General Unsecured Claims.The Predecessor Company’s general unsecured claims, including 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 (collectively, the “Senior Unsecured Notes”) and the 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, 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 New Common Stock, 5.2 million of which was issued immediately upon emergence, and (c) 4.9 million Series A Warrants and 2.1 million Series B Warrants, with initial exercise prices of $41.34 and $42.03 per share, respectively, which expire on October 4, 2022, (the “Warrants”). Approximately 4.5 million Series A Warrants and 1.9 million Series B Warrants were issued immediately upon emergence.

• New Building Note. A note with a principal amount of $35.0 million ($36.6 million fair value on the Emergence Date), which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) 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 Unsecured Senior Notes.

• Preferred and Common Stock. The Predecessor Company’s 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.

See “Note 1 - Voluntary Reorganization under Chapter 11 Proceedings,” “Note 11 - Debt” and “Note 15 - Equity” to the consolidated financial statements included in Item 8 of this report for additional information on the transactions noted above.

2016 Operational Activities

Operational highlights for 2016 include the following:

• Total production for 2016 was comprised of approximately 28.5% oil, 49.0% natural gas and 22.5% NGLs compared to 32.0% oil, 51.2% natural gas and 16.8% NGLs in 2015.

• Reduced the total rigs drilling to one at December 31, 2016 from four at December 31, 2015.

• Drilled 16 wells in the Mid-Continent and 10 wells in the Rockies in 2016 compared to drilling 161 wells, excluding salt water disposal wells, in the Mid-Continent and no wells in the Rockies in 2015, respectively.

• Discontinued all remaining drilling and oilfield services operations in 2016, and as a result, our drilling and oilfield services operations no longer constituted a reportable segment in 2016.

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• Transferred substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO and $11.0 million in cash to Occidental in January 2016 in exchange for the release from all past, current and future claims and obligations under an existing 30-year treating agreement between the companies. This resulted in a substantial decrease in our marketing and midstream operations throughout 2016, and accordingly, our midstream and marketing operations no longer constituted a reportable segment at December 31, 2016.

Outlook

We have established a range for our 2017 capital expenditures budget between $210.0 million and $220.0 million, with the substantial majority of the budgeted expenditures being designated for exploration and production activities.

Our estimated proved reserve volumes were 163.9 MMBoe at December 31, 2016, based on independent petroleum engineer estimates using the SEC-mandated historical 12-month unweighted average pricing at such date, which were $39.25 per barrel of oil and $2.48 per Mcf of natural gas. Replacing the January 1, 2016 and February 1, 2016 price components with actual January 1, 2017, and February 1, 2017 benchmark commodities prices, the 12-month unweighted average prices would have been $42.50 per barrel of oil and $2.66 per Mcf of natural gas. Holding our December 31, 2016 reserves estimates and other variables constant and applying the 12-month unweighted average prices through February 1, 2017, our internally estimated proved reserves would not decrease further in the first quarter of 2017. If commodity pricing falls short of our current expectations or rebounds to a level supportive of more drilling, we may change our 2017 capital expenditure plans again. However, we do not expect these short term changes to negatively impact our ability to develop all of our December 31, 2016 proved undeveloped locations within a five year time frame. All reserve estimates for periods after December 31, 2016 provided in this Form 10-K were determined by Company reservoir engineers and, accordingly, have not been fully assessed by independent petroleum consultants.

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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,
	2016		2015		2014		2013		2012
Oil (per Bbl)	$	43.47	$	48.75	$	92.91	$	98.05	$	94.15
Natural gas (per Mcf)	$	2.55	$	2.62	$	4.26	$	3.73	$	2.83

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.

Acquisitions and Divestitures

Divestiture of WTO Properties and Release from Treating Agreement. On January 21, 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.

Acquisition of Rockies Properties. In December 2015, we acquired approximately 135,000 net acres in the North Park Basin, Jackson County, Colorado, including working interests in 16 wells previously drilled on the acreage, for approximately $191.1 million in cash, including post-closing adjustments. Additionally, the seller paid us $3.1 million for certain overriding interests retained in the properties. We began developing the acquired acreage in early 2016.

Acquisition of Piñon Gathering Company, LLC. In October 2015, we acquired the assets of and terminated a gas gathering agreement with PGC for $48.0 million cash and $78.0 million principal amount of Senior Secured Notes. PGC’s assets consisted of approximately 370 miles ofgathering lines that supported our production in the Piñon field in West Texas. The transaction resulted in the termination of a gas gathering agreement with PGC under which we were required to compensate PGC for any throughput shortfalls below a required minimum volume. The fair value of the consideration we paid, including the discount attributable to the Senior Secured Notes issued, was approximately $98.3 million and was allocated on a relative fair value basis between the assets acquired (approximately $47.3 million) and a loss on the termination of the gathering contract (approximately $51.0 million). These assets were subsequently transferred to Occidental in the divestiture of the WTO properties discussed above.

Gulf of Mexico and Gulf Coast Properties. On February 25, 2014, we sold subsidiaries that owned the Gulf Properties, for approximately $702.6 million, net of working capital adjustments and post-closing adjustments, and the buyer’s assumption of approximately $366.0 million of related asset retirement obligations. We retained a 2% overriding royalty interest in certain exploration prospects. The proceeds from the sale were used to fund our drilling in the Mid-Continent. This transaction did not result in a significant alteration of the relationship between our capitalized costs and proved reserves and, accordingly, the proceeds were recorded as a reduction to the full cost pool with no gain or loss on the sale.

Production, revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties included in the Company’s results for the year ended December 31, 2014, was as follows:

	Year Ended December 31,
	2014(1)
Production (MBoe)	1,321
Revenues (in thousands)	$	90,920
Expenses (in thousands)	$	63,674

_______________

(1)    Includes activity through February 25, 2014, the date of sale.

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Oil, Natural Gas and NGL Production and Pricing

Set forth in the table below is production and pricing information for Successor Company and the Predecessor Company for the respective 2016 periods and the years ended December 31, 2016, 2015 and 2014.

	Successor		Predecessor		Combined		Predecessor
	Period from October 2, 2016 through December 31,		Period from January 1, 2016 through October 1,		Year Ended December 31,		Year Ended December 31,
	2016		2016		2016		2015		2014
Production data (in thousands)
Oil (MBbls)	1,214		4,315		5,529		9,600		10,876
NGL (MBbls)	999		3,358		4,357		5,044		3,794
Natural gas (MMcf)	12,771		44,124		56,895		92,105		85,697
Total volumes (MBoe)	4,342		15,027		19,369		29,995		28,953
Average daily total volumes (MBoe/d)	47.7		54.6		52.9		82.2		79.3
Average prices—as reported(1)
Oil (per Bbl)	$	47.03	$	36.85	$	39.09	$	45.83	$	89.86
NGL (per Bbl)	$	14.77	$	12.67	$	13.15	$	14.36	$	33.41
Natural gas (per Mcf)	$	2.07	$	1.78	$	1.84	$	2.12	$	3.70
Total (per Boe)	$	22.64	$	18.63	$	19.53	$	23.59	$	49.08
Average prices—including impact of derivative contract settlements(2)
Oil (per Bbl)	$	54.59	$	51.05	$	51.83	$	76.80	$	94.18
NGL (per Bbl)	$	14.77	$	12.67	$	13.15	$	14.36	$	33.41
Natural gas (per Mcf)	$	1.96	$	1.77	$	1.81	$	2.45	$	3.58
Total (per Boe)	$	24.41	$	22.70	$	23.08	$	34.51	$	50.36

____________________

(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 Successor 2016 Period and the Predecessor 2016 Period and the years ended December 31, 2015 and 2014 and illustrates the impact of (i) the continued decrease in capital expenditures and number of new wells drilled in the Mid-Continent, Permian and other regions, (ii) the sale of the Gulf Properties in 2014, and (iii) the acquisition of the Rockies properties in December 2015.

	Successor			Predecessor
	Period from October 2, 2016 through December 31,			Period from January 1, 2016 through October 1,			Year Ended December 31,
	2016			2016			2015			2014
	Production (MBoe)	% of Total Production		Production (MBoe)	% of Total Production		Production (MBoe)	% of Total Production		Production (MBoe)	% of Total Production
Mid-Continent	4,018	92.5	%	14,119	94.0	%	26,558	88.5	%	23,423	80.9	%
Rockies	180	4.1	%	320	2.1	%	—	—	%	—	—	%
Gulf of Mexico / Gulf Coast	—	—	%	—	—	%	—	—	%	1,321	4.6	%
Permian Basin	144	3.4	%	489	3.3	%	1,567	5.2	%	2,076	7.2	%
Other	—	—	%	99	0.6	%	1,870	6.3	%	2,133	7.3	%
Total	4,342	100.0	%	15,027	100.0	%	29,995	100.0	%	28,953	100.0	%

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Revenues

Consolidated revenues for the Successor 2016 Period, the Predecessor 2016 Period, and the years ended December 31, 2016, 2015 and 2014 are presented in the table below (in thousands).

	Successor		Predecessor				Predecessor
	Period from October 2, 2016 through December 31,		Period from January 1, 2016 through October 1,		Combined Year Ended December 31,		Year Ended December 31,
	2016		2016		2016		2015		2014
Revenues
Oil	$	57,093	$	159,023	$	216,116	$	439,927	$	977,269
NGL	14,756		42,541		57,297		72,440		126,759
Natural gas	26,458		78,407		104,865		195,067		316,851
Other	149		13,838		13,987		61,275		137,879
Total revenues(1)	$	98,456	$	293,809	$	392,265	$	768,709	$	1,558,758

___________________

(1) Includes $57.0 million and $150.4 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2015 and 2014, respectively.

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, 2016 and 2015 are shown in the table below (in thousands):

2014 oil, natural gas and NGL revenues	$	1,420,879
Change due to production volumes in 2015	(49,143		)
Change due to average prices in 2015	(664,302		)
2015 oil, natural gas and NGL revenues	707,434
Change due to production volumes in 2016	(270,688		)
Change due to average prices in 2016	(58,468		)
2016 oil, natural gas and NGL revenues (Supplemental pro forma combined)	$	378,278

Oil, natural gas and NGL revenues decreased by a combined $329.2 million, or 46.5% for the year ended December 31, 2016 compared to 2015. The decrease is due largely to lower oil and natural gas production, primarily due to natural declines in existing producing wells, the decrease in new wells drilled during 2016 compared to 2015, and the proportionate consolidation of the Royalty Trusts’ activities during the 2016 period. The remaining decrease is primarily due to a decline in the average prices received as a result of declining market prices for oil production, and to a lesser extent, natural gas and NGL production. The decline in average prices received also includes the effects of the Successor Company’s election to include transportation deductions in revenues for the Successor 2016 Period.

Oil, natural gas and NGL sales decreased by a combined $713.4 million, or 50.2% for the year ended December 31, 2015 compared to 2014, primarily due to a decline in the average prices received for our oil production, and to a lesser extent lower gas and NGL production.    

Other revenues primarily include drilling and oilfield services and marketing and midstream sales, which decreased in 2016 compared to 2015 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 Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2016, 2015 and 2014 are presented below.

	Successor		Predecessor		Combined		Predecessor
	Period from October 2, 2016 through December 31,		Period from January 1, 2016 through October 1,		Year Ended December 31,		Year Ended December 31,
	2016		2016		2016		2015			2014
	(In thousands)
Expenses
Production	$	24,997	$	129,608	$	154,605	$	308,701		$	346,088
Production taxes	2,643		6,107		8,750		15,440			31,731
Depreciation and depletion—oil and natural gas	33,971		86,613		120,584		319,913			434,295
Depreciation and amortization—other	3,922		21,323		25,245		47,382			59,636
Accretion of asset retirement obligations	2,090		4,365		6,455		4,477			9,092
Impairment	319,087		718,194		1,037,281		4,534,689			192,768
General and administrative	9,837		116,091		125,928		137,715			113,991
Employee termination benefits	12,334		18,356		30,690		12,451			8,874
Loss (gain) on derivative contracts	25,652		4,823		30,475		(73,061		)	(334,011		)
Loss on settlement of contract	—		90,184		90,184		50,976			—
Other operating expenses	268		4,348		4,616		52,704			106,070
Total expenses(1)	$	434,801	$	1,200,012	$	1,634,813	$	5,411,387		$	968,534

___________________

(1) Includes $679.9 million and $51.0 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2015 and 2014, respectively. The expenses attributable to noncontrolling interest in consolidated VIEs include $655.9 million and $29.9 million of allocated full cost ceiling impairment for the years ended December 31, 2015 and 2014, respectively.

Production expense includes the costs associated with our exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses for 2016 decreased $154.1 million, or 49.9% from 2015. Production costs per Boe decreased to $7.98 per Boe for the 2016 period from $10.29 per Boe in 2015, primarily due to (i) a decrease in well activity due to fewer new wells being brought on production, (ii) termination of the CO₂ delivery agreement with Occidental in the first quarter of 2016, which resulted in CO₂ delivery shortfall penalties of $2.0 million being incurred in the Predecessor 2016 Period compared to penalties of $34.9 million incurred during 2015, and (iii) the presentation of $7.4 million of transportation costs as a reduction from revenues in the Successor 2016 Period versus the Predecessor Company’s presentation of these costs as production expenses. The Predecessor 2016 Period includes approximately $26.2 million of transportation costs.

Production expenses for 2015 decreased $37.4 million, or 10.8% from 2014. Production costs per Boe decreased to $10.29 per Boe for the 2015 period from $11.95 per Boe in 2014, primarily as a result of (i) the sale of the Gulf Properties in February 2014, which had higher production costs inherent with offshore operations, and (ii) a decrease in well activity as a result of fewer new wells being brought on production and a reduction in workover activity in 2015 in conjunction with an increase in combined production for the year ended December 31, 2015 compared to 2014.

Production taxes decreased by $6.7 million, or 43.3%, for 2016, compared to 2015, and decreased by $16.3 million, or 51.3%, for 2015, compared to 2014, primarily due to the decrease in oil, natural gas and NGL revenues. Production taxes as a percentage of oil, natural gas and NGL revenue were consistent at approximately 2.3% for 2016, and 2.2% for both 2015 and 2014.

Depreciation and depletion for oil and natural gas properties for the Successor 2016 Period was recorded at an average depreciation and depletion rate of $7.82 per Boe, which reflects an increase in reserve values due to fresh start valuation adjustments recorded for reserves as of October 1, 2016. The average depreciation and depletion rate for the Predecessor 2016 Period of $5.76 per Boe, decreased from a rate of $10.67 per Boe in 2015, primarily due to full cost ceiling impairments recorded in 2016, and the proportionate consolidation of the Royalty Trusts’ activities during 2016.

56

Depreciation and depletion for oil and natural gas properties decreased by $114.4 million for the year ended December 31, 2015, compared to 2014. This decrease largely resulted from a reduction in the average depreciation and depletion rate per Boe to $10.67 for 2015 from $15.00 for 2014, primarily resulting from (i) the sale of the Gulf Properties in February 2014 (ii) full cost ceiling impairments recorded in 2015 and (iii) changes in future production and planned capital expenditures that occurred in conjunction with the year end 2014 budgeting and reserves estimation processes.

Depreciation and depletion for non-oil and gas properties decreased 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 Successor 2016 Period and the Predecessor 2016 Period and the years ended December 31, 2016, 2015 and 2014 consisted of the following (in thousands):

	Successor		Predecessor		Combined		Predecessor
	Period from October 2, 2016 through December 31,		Period from January 1, 2016 through October 1,		Year Ended December 31,		Year Ended December 31,
	2016		2016		2016		2015		2014
Impairment
Full cost pool ceiling limitation	$	319,087	$	657,392	$	976,479	$	4,473,787	$	164,779
Drilling assets	—		3,511		3,511		37,646		27,428
Electrical transmission system	—		55,600		55,600		—		—
Midstream assets	—		1,691		1,691		7,148		561
Other	—		—		—		16,108		—
Total impairment	$	319,087	$	718,194	$	1,037,281	$	4,534,689	$	192,768

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 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 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 2015 and the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes. The decrease in projected production volumes resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that have been developed with three or more horizontal wells per section as inter-well pressure communication has had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in the Company’s Mississippian wells producing with artificial lift have resulted in increased production decline rates that are now becoming more predictable on a large group of base wells as this population of wells has been producing for more than two years.

Impairment recorded in 2014 was due to a full cost ceiling limitation resulting from the divestiture of the Gulf Properties in the first quarter of 2014 as the present value of future net revenues associated with the Gulf Properties exceeded the associated reduction to the full cost pool.

Drilling asset impairment. Impairments were recorded on certain drilling assets in the years ended December 31, 2016, and 2015 upon determining their future use was limited after discontinuing drilling operations in the Permian region in 2015 and discontinuing all remaining drilling operations in 2016. Impairment in 2014 was to adjust the carrying value of certain drilling assets classified as held for sale to fair value after classifying certain assets as held for sale or determining that the future use of assets held and used was limited.

Electrical transmission system impairment. Impairment in 2016 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.

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Midstream asset impairment. Impairment recorded on midstream assets in 2016 and 2015 resulted primarily from the write-downs of generators, compressors and various other equipment, due to their limited use.

Other impairment. Impairment recorded on other assets in 2015, includes a $15.4 million impairment on property located in downtown Oklahoma City, Oklahoma to adjust the carrying value of the property to the agreed upon sales price for which it was later sold in 2016.

General and administrative expenses decreased $11.8 million, or 8.6%, for the year ended December 31, 2016 compared to 2015 due primarily to (i) an $8.4 million decrease in net payroll costs, and (ii) a decrease of $5.0 million due to recording a legal settlement in 2015. The remainder of the decrease in general and administrative expenses resulted primarily from a reduction in various other corporate support costs including office costs, travel, employee placement, training, vehicle and technology costs due to reductions in force in the first and fourth quarters of 2016 and corporate cost cutting measures. These reductions were partially offset by an increase of $8.2 million in professional services costs, which primarily related to consulting fees incurred for the restructuring of the Company prior to the Chapter 11 filings and after the Emergence Date.

General and administrative expenses increased $23.7 million, or 20.8%, for the year ended December 31, 2015 compared to 2014 due primarily to (i) an increase of $14.6 million in professional services costs, including legal and consulting fees, (ii) an increase of $5.0 million due to a legal settlement recorded in 2015, and (iii) a $4.0 million increase in net payroll costs, primarily resulting from a decrease in capitalized salary costs.

Employee termination benefits for the year ended December 31, 2016 represent 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.

Employee termination benefits recorded in 2015 represent severance costs incurred primarily as a result of (i) a reduction in force (ii) severance costs associated with the departure of an executive officer and other senior officers and (iii) discontinuing all remaining drilling and oilfield services operations in the Permian region in 2015. Employee termination benefits recorded in 2014 represent severance costs incurred primarily in conjunction with the sale of the Gulf Properties.

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, which includes net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. Included in the net receipts for the Predecessor 2016 Period is $17.9 million related to settlements of contracts prior to their contractual maturity (“early settlements”) in the second quarter of 2016, primarily in response to the Chapter 11 Petitions being filed.

We recorded gains on commodity derivative contracts of $73.1 million and $334.0 million for the years ended December 31, 2015 and 2014, respectively, as reflected in consolidated statements of operations included in Item 8 of this report, which includes net cash (receipts) payments upon settlement of $(327.7) million and $32.3 million, respectively. Included in the net cash payments for 2014 are $69.6 million of cash payments related to early settlements primarily as a result of the sale of the Gulf Properties in February 2014.

Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded each quarter as a component of operating expenses. Internally, management views the settlement of derivative contracts at contractual maturity as adjustments to the price received for oil and natural gas production to determine “effective prices.” Gains or losses on early settlements and losses related to amendments of contracts are not considered in the calculation of effective prices. In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our oil and natural gas price swaps. 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 oil and natural gas price swaps.

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.

Loss on settlement of contract in 2015 resulted from the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. See “—Acquisitions and Divestitures” above and see “Note 5—Acquisitions and Divestitures” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the acquisition of PGC and the PGC gathering agreement.

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Other Income (Expense), Taxes and Net (Loss) Income Attributable to Noncontrolling Interest

Other income (expense), taxes and net (loss) income attributable to noncontrolling interest for the Successor 2016 Period and the Predecessor 2016 Period and the years ended December 31, 2015 and 2014 are reflected in the table below (in thousands).

	Successor			Predecessor			Combined			Predecessor
	Period from October 2, 2016 through December 31,			Period from January 1, 2016 through October 1,			Year Ended December 31,			Year Ended December 31,
	2016			2016			2016			2015			2014
Other income (expense)
Interest expense	$	(372	)	$	(126,099	)	$	(126,471	)	$	(321,421	)	$	(244,109	)
Gain on extinguishment of debt	—			41,179			41,179			641,131			—
Reorganization items	—			2,430,599			2,430,599			—			—
Other income, net	2,744			1,332			4,076			2,040			3,490
Total other income (expense)	2,372			2,347,011			2,349,383			321,750			(240,619		)
(Loss) income before income taxes	(333,973		)	1,440,808			1,106,835			(4,320,928		)	349,605
Income tax expense (benefit)	9			11			20			123			(2,293		)
Net (loss) income	(333,982		)	1,440,797			1,106,815			(4,321,051		)	351,898
Less: net (loss) income attributable to noncontrolling interest	—			—			—			(623,506		)	98,613
Net (loss) income attributable to SandRidge Energy, Inc.	$	(333,982	)	$	1,440,797		$	1,106,815		$	(3,697,545	)	$	253,285

Interest expense for the Successor Company and Predecessor Company for the respective 2016 periods and the years ended December 31, 2016, 2015 and 2014 consisted of the following (in thousands):

	Successor			Predecessor			Combined			Predecessor
	Period from October 2, 2016 through December 31,			Period from January 1, 2016 through October 1,			Year Ended December 31,			Year Ended December 31,
	2016			2016			2016			2015			2014
Interest expense
Interest expense on debt	$	1,590		$	123,350		$	124,940		$	304,020		$	254,475
Amortization of debt issuance costs, premium and discounts	(81		)	7,730			7,649			15,014			9,954
Write off of debt issuance costs	—			—			—			7,108			—
(Gain) loss on long-term debt derivatives	—			(1,324		)	(1,324		)	10,377			—
Capitalized interest	—			(2,240		)	(2,240		)	(14,018		)	(19,718		)
Total	1,509			127,516			129,025			322,501			244,711
Less: interest income	(1,137		)	(1,417		)	(2,554		)	(1,080		)	(602		)
Total interest expense	$	372		$	126,099		$	126,471		$	321,421		$	244,109

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.

Total interest expense decreased $195.0 million for the year ended December 31, 2016 compared to 2015, primarily due to (i) ceasing to record interest expense on the Senior Unsecured Notes at the time of the Chapter 11 filings, (ii) the repurchase of Senior Unsecured Notes in 2015, (iii) conversion of Convertible Senior Unsecured Notes into shares of the Predecessor Company’s common stock in the second half of 2015 and first quarter of 2016, and (iv), repayment of all amounts outstanding under the First Lien Exit Facility in October 2016. These decreases were partially offset by (i) interest expense and amortization of discount and debt issuance costs associated with the Senior Secured Notes issued in June and October 2015 through the date of the Chapter 11 filings, and (ii) a reduction in the amount of interest capitalized in the 2016 periods, primarily due to a decrease in drilling activity.

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Total interest expense increased $77.3 million for the year ended December 31, 2015 compared to 2014, primarily due to interest expense associated with the $1.25 billion in Senior Secured Notes issued in June 2015. This increase was partially offset by a decrease in interest paid on Senior Unsecured Notes that were repurchased or converted into shares of the Predecessor Company’s common stock in 2015 as well as the loss recognized due to an increase in the fair value of derivatives embedded in certain of the Company’s long-term debt during the year ended December 31, 2015.

We recognized a gain on extinguishment of debt of $41.2 million in the Predecessor 2016 Period, primarily in connection with the exchange of approximately $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.

We recognized a gain on extinguishment of debt of $641.1 million for the year ended December 31, 2015, primarily in connection with (i) the exchange of $575.0 million in aggregate principal of Senior Unsecured Notes for Convertible Senior Unsecured Notes, (ii) the repurchase of $350.0 million in aggregate principal of Senior Unsecured Notes for approximately $124.5 million in cash, (iii) the exchange of approximately $50.0 million aggregate principal of 7.5% Senior Unsecured Notes due 2021 and 8.125% Senior Unsecured Notes due 2022 for shares of the Company’s common stock, and (iv) conversions of Convertible Senior Unsecured Notes into shares of the Company’s common stock.

See “Note 11—Long-Term Debt” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the Company’s 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 - Fresh Start Accounting” to the consolidated financial statements included in Item 8 of this Report for further discussion of reorganization items.

Tax expense and the effective tax rate for the Successor 2016 Period and the Predecessor 2016 Period and the year ended December 31, 2015 were low as a result of the valuation allowance against our net deferred tax asset in each period. The Company’s income tax benefit of $2.3 million for the year ended December 31, 2014 is primarily related to a reduction in the Company’s gross unrecognized tax benefits following a favorable outcome pertaining to the Company’s state income tax audits in the amount of $1.3 million as well as a reduction in federal alternative minimum tax (“AMT”) associated with the tax year ended December 31, 2014 in the amount of $1.2 million. With respect to the AMT, the Company reduced each of the current tax liability and corresponding deferred tax asset upon finalizing and filing the Company’s federal income tax return for the year ended December 31, 2014. As a result of reducing the deferred tax asset, the Company decreased its valuation allowance against its net deferred tax asset by $1.2 million.

Net (loss) income attributable to noncontrolling interest in 2015 and 2014 primarily represents the portion of (loss) income attributable to third-party ownership in the Royalty Trusts, and was significantly impacted by full cost ceiling impairments attributable to noncontrolling interest of $655.9 million in 2015, and $29.9 million in 2014. Revenues for the Royalty Trusts also decreased in 2015 compared to 2014 as a result of a decrease in average prices received for production, natural declines in production and a reduction in the average number of producing wells as uneconomic wells were shut-in due to depressed commodity pricing. Additionally, net gains recorded on the Royalty Trusts’ derivative contracts decreased primarily due to the expiration of the Permian Trust’s derivative contracts in the first quarter of 2015. The Company fulfilled its drilling obligations to the Mississippian Trust I in the second quarter of 2013, to the Permian Trust in the fourth quarter of 2014 and to the Mississippian Trust II in the first quarter of 2015. No further wells will be drilled for the Royalty Trusts.

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Liquidity and Capital Resources

At December 31, 2016, we had cash and cash equivalents of $121.2 million, approximately $305.3 million in total debt outstanding and $8.6 million in outstanding letters of credit with no amount outstanding under the First Lien Exit Facility. As of December 31, 2016, the First Lien Exit Facility had an available borrowing base of $425.0 million, which was reduced by the $8.6 million in outstanding letters of credit. As of February 24, 2017, the Company’s cash, cash equivalents and cash classified as restricted for the payment of general unsecured claims related to the Company’s emergence from Chapter 11, were approximately $127.1 million.

Working Capital and Sources and Uses of Cash

Our principal sources of liquidity for 2017 include cash flow from operations, cash on hand and amounts available under our refinanced credit facility, as discussed in “—Credit Facilities” below.

Significant transactions affecting our future liquidity upon emergence from Chapter 11 included the elimination of approximately $3.7 billion in senior notes and related accrued interest, and issuance of the $35.0 million New Building Note, for which interest is expected to be paid in cash beginning in 2017.

Additionally, our working capital surplus decreased to $43.5 million at December 31, 2016 compared to $236.7 million at December 31, 2015, largely due to fluctuations in the timing and amount of collections of receivables and a decrease in accounts payable resulting from a reduction in drilling activity in 2016.

We have established a range for our 2017 capital expenditures budget between $210.0 million and $220.0 million, with the substantial majority of the budgeted expenditures being designated for exploration and production activities. Management intends to fund 2017 capital expenditures using cash flow from operations, cash on hand and, if necessary, borrowings under the refinanced credit facility discussed below.

Cash Flows

Our cash flows from operations are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile. For example, for oil, from January 2012 through December 2016, the highest month end NYMEX settled price was $107.65 per Bbl and the lowest was $33.62 per Bbl. For natural gas, from January 2012 through December 2016, the highest month-end NYMEX settled price was $5.56 per MMBtu and the lowest was $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 further full cost pool ceiling impairments. Further, if our future capital expenditures are limited or deferred, or we are unsuccessful in developing reserves and adding production through our capital program, the value of our oil and natural gas properties, financial condition and results of operations could be adversely affected.

Cash flows for the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2016, 2015 and 2014 are presented in the following table and discussed below (in thousands):

	Successor			Predecessor			Combined			Predecessor
	Period from October 2, 2016 through December 31,			Period from January 1, 2016 through October 1,			Year Ended December 31,			Year Ended December 31,
	2016			2016			2016			2015			2014
Cash flows provided by (used in) operating activities	$	65,595		$	(112,077	)	$	(46,482	)	$	373,537		$	621,114
Cash flows used in investing activities	(39,835		)	(167,690		)	(207,525		)	(1,039,640		)	(857,241		)
Cash flows (used in) provided by financing activities	(415,061		)	407,551			(7,510		)	920,438			(397,283		)
Net (decrease) increase in cash and cash equivalents	$	(389,301	)	$	127,784		$	(261,517	)	$	254,335		$	(633,410	)

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Cash Flows from Operating Activities

The $420.0 million reduction in operating cash flows for the year ended December 31, 2016 compared to 2015, is primarily due to a decrease in revenues from oil, natural gas and NGLs, a reduction in proceeds received on settlement of commodity derivative contracts, an increase in professional and other fees paid in connection with the Company’s restructuring in 2016, and the reduction in working capital noted above. These were partially offset by a reduction of $190.6 million in cash paid for interest expense and lower production expenses paid in 2016 compared to 2015.

The $247.6 million reduction in operating cash flows for the year ended December 31, 2015 compared to 2014 was also primarily due to a decrease in revenues from oil, natural gas and NGL production, which was partially offset by proceeds received on the settlement of commodity derivative contracts and, to a lesser extent, a reduction in operating expenses during 2015.

Cash Flows from Investing Activities

The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the exploration for and production of oil and natural gas. These capital expenditures are necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and natural gas industry.

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

During the year ended December 31, 2015, cash flows used in investing activities largely consisted of capital expenditures, excluding acquisitions, as well as cash paid for the North Park acquisition and the PGC assets acquired. During the year ended December 31, 2014, cash flows used in investing activities resulted from capital expenditures, excluding acquisitions, of approximately $1.6 billion, which were partially offset by proceeds from the sale of assets of $714.5 million, primarily generated by the sale of the Gulf Properties.

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, for the Successor 2016 Period, the Predecessor 2016 Period and the years ended December 31, 2016, 2015 and 2014 are summarized below (in thousands):

	Successor		Predecessor		Combined		Predecessor
	Period from October 2, 2016 through December 31,		Period from January 1, 2016 through October 1,		Year Ended December 31,		Year Ended December 31,
	2016		2016		2016		2015		2014
Capital expenditures
Exploration and production	$	38,062	$	155,627	$	193,689	$	656,022	$	1,508,100
Drilling and oilfield services	—		23		23		4,632		18,385
Midstream services	2,901		3,085		5,986		21,556		44,606
Other	83		2,672		2,755		19,405		37,798
Capital expenditures, excluding acquisitions	41,046		161,407		202,453		701,615		1,608,889
Acquisitions	—		1,328		1,328		241,165		18,384
Total	$	41,046	$	162,735	$	203,781	$	942,780	$	1,627,273

Capital expenditures, excluding acquisitions, decreased significantly for the year ended December 31, 2016 compared to 2015, due to a decrease in drilling activity.

Capital expenditures, excluding acquisitions, also decreased significantly for the year ended December 31, 2015 compared to 2014, primarily due to a decrease in drilling and leasehold expenditures in the Mid-Continent area. The number of drilling rigs operating on the Company’s properties decreased to four rigs at December 31, 2015 from 35 rigs at December 31, 2014, largely in response to the sharp decline in oil prices during 2014. During the year ended December 31, 2014, the Company received payments for drilling carries from Atinum MidCon I, LLC’s (“Atinum”) and Repsol E&P USA, Inc. (“Repsol”) of approximately $205.6 million, which directly offset the Company’s capital expenditures. Both Atinum and Repsol fully funded their drilling carry commitments during 2014.

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During the fourth quarter of 2015, the Company acquired (i) all of the assets of PGC for approximately $47.3 million and (ii) approximately 135,000 net acres and 16 existing oil and natural gas wells in the North Park Basin of the Rockies, in Jackson County, Colorado for approximately $191.1 million in cash, including post-closing adjustments. The seller of the North Park Basin properties also paid the Company $3.1 million for certain overriding interests retained in the properties, which slightly offset acquisition expenditures.

Cash Flows from Financing Activities

Cash used in financing activities 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 New Building Note, which were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan.

The Company’s financing activities provided $920.4 million in cash for the year ended December 31, 2015 compared to using $397.3 million of cash in 2014. The change is due primarily to (i) the issuance of $1.25 billion in Senior Secured Notes in June 2015, which was partially offset by $124.5 million in cash paid for the repurchase of debt, and debt issuance costs incurred of $53.2 million, (ii) a decrease of $55.5 million in noncontrolling interest distributions, and (iii) a decrease of $44.3 million in preferred dividends paid in cash during the 2015 period compared to the 2014 period, and (iv) proceeds from the sale of Royalty Trust units of $22.1 million. These increases were partially offset by a net payment of $111.3 million to repurchase 27.4 million shares of the Company’s common stock, and $44.1 million for the early settlement of financing derivatives as a result of the sale of the Gulf Properties.

Indebtedness

Long-term debt consists of the following at December 31, 2016 (in thousands):

First Lien Exit Facility	$	—
New Convertible Notes	268,780
New Building Note	36,528
Total debt	$	305,308

The Chapter 11 filings constituted an event of default with respect to the Predecessor Company’s existing debt obligations, causing the Predecessor Company's pre-petition senior credit facility, Senior Secured Notes, Senior Unsecured Notes and Convertible Senior Unsecured Notes to become immediately due and payable. As a result of the Chapter 11 filings, any efforts to enforce such payment obligations were automatically stayed through the Emergence Date, when the Predecessor Company’s debt was canceled. For the Successor 2016 Period, there were no applicable financial covenants with which we had to comply under the First Lien Exit facility, the outstanding New Convertible Notes or the New Building Note.

Credit Facilities

On the Emergence Date, the Company entered into the New First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender. The initial borrowing base under the New First Lien Exit Facility was $425.0 million, with a maturity date on February 4, 2020. There were no scheduled borrowing base redeterminations until October 2018, followed by scheduled semiannual borrowing base redeterminations thereafter. The outstanding borrowings under the New First Lien Exit Facility bore interest at a rate equal to, at the option of the Company, either (a) a base rate plus an applicable rate of 3.75% per annum or (b) LIBOR plus 4.75% per annum, subject to a 1.00% LIBOR floor. Interest on base rate borrowings was payable quarterly in arrears and interest on LIBOR borrowings was payable every one, two, three or six months, at the election of the Company. The Company had the right to prepay loans under the New First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans.

The New First Lien Exit Facility contained customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants. We were in compliance with these covenants as of and for the period ended December 31, 2016.

On February 10, 2017, the New First Lien Exit Facility was refinanced into a new $600.0 million refinanced credit facility with a $425.0 million borrowing base. The refinanced credit facility agreement had the following impacts:

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• increased the principal amount of commitments to $600.0 million from $425.0 million;

• extended the maturity date to March 31, 2020 from February 4, 2020;

• borrowing base determinations now include the Company’s proportionately consolidated share of proved reserves held by the Royalty Trusts;

• reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to 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;

• reduced the LIBOR floor from 1% to 0%;

• eliminated the minimum proved developing producing reserves asset coverage ratio;

• removed the requirement to maintain $50.0 million in a cash collateral account controlled by the administrative agent;

• eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and

• eliminated certain negative covenants, such as the $20.0 million liquidity requirement and the limitation on capital expenditures.

The initial conforming borrowing base under the refinanced credit facility is $425.0 million and the next borrowing base redetermination is scheduled for October 1, 2017, followed by semiannual borrowing base redeterminations thereafter. The amended 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 most recently delivered reserve report of the Company, (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 described above, the refinanced credit facility refinanced and thereby replaced the First Lien Exit Facility.

The refinanced credit facility requires the company to, commencing with the first full quarter ending after the effective date of the refinancing, 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. Such financial covenants are subject to customary cure rights.

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

The refinanced 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 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.

At February 24, 2017, there were no amounts outstanding under the refinanced credit facility and approximately $8.0 million in outstanding letters of credit, which reduced the availability under the refinanced credit facility on a dollar for dollar basis.

New Convertible Debt    

On the Emergence Date, pursuant to the terms of the Plan, the Company issued approximately $281.8 million principal amount of New Convertible Notes, which did not bear regular interest and were scheduled to mature and mandatorily convert into New Common Stock on October 4, 2020, unless repurchased, redeemed or converted prior to that date. The New Convertible Notes were recorded at fair value upon implementation of fresh start accounting, with the $163.9 million excess value over par recorded as additional paid in capital.

The New Convertible Notes were convertible at the option of the holders at any time up to, and including, the business day immediately preceding the maturity date at an initial convertible at a conversion rate of 0.05330841 shares of New Common Stock per $1.00 principal amount of New Convertible Notes. During the Successor 2016 Period, holders converted approximately $13.0 million par value of New Convertible Notes into approximately 0.7 million shares of New Common Stock. From January

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1, 2017 through February 9, 2017, holders converted an additional $5.1 million par value of New Convertible Notes into approximately 0.3 million shares of New Common Stock.

The New Convertible Notes were mandatorily convertible upon certain events, including upon the bona fide refinancing of the New First Lien Exit Facility after a determination by the post-emergence board of directors in good faith that: (a) such refinancing provides for terms that are materially more favorable to the Company and (b) the causing of a conversion is not the primary purpose of such refinancing. As a result of refinancing of New First Lien Exit Facility on February 10, 2017, the remaining outstanding $263.7 million par value of New Convertible Notes on that date converted into approximately 14.1 million shares of New Common Stock.

New Building Note

On the Emergence Date, the Company entered into the New Building Note, which has a principal amount of $35.0 million and is secured by first priority mortgage on the Company’s headquarters facility and certain other non-oil and gas real property in downtown Oklahoma City, Oklahoma. The New Building Note was recorded at fair value upon implementation of fresh start accounting. Interest is payable on the New Building Note at 6% per annum for the first year following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. Interest is payable in kind from the Emergence Date through the refinancing or repayment of the New First Lien Exit Facility and thereafter in cash. The New Building Note matures on October 4, 2021. On the Emergence Date, pursuant to the Plan, certain holders of the Predecessor Company’s Unsecured Senior Notes purchased the New Building Note for $26.8 million in cash, net of certain fees and expenses. The majority of these proceeds were then immediately paid out to certain creditors in accordance with the terms of the Plan. As a result of the Company’s entry into the refinanced credit facility, interest on the New Building Note will be paid in cash beginning in 2017. Additionally, the New Building Note was amended in February 2017 in order to allow for pre-payment of principal outstanding.

See “Note 1 - Voluntary Reorganization under Chapter 11 Proceedings ” and “Note 11 - Long-Term Debt” to the accompanying consolidated financial statements included in Item 8 of this report for additional discussion of the Company’s debt.

Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2016, our contractual obligations included long-term debt obligations, third-party drilling rig agreements, asset retirement obligations, operating leases and other individually insignificant obligations. During 2016, the Bankruptcy Court issued orders allowing the rejection of certain long-term contracts that were previously outstanding at December 31, 2015.

As of December 31, 2016, we had future contractual payment commitments under various agreements, which are summarized below. The third-party drilling rig and operating leases are not recorded in the accompanying consolidated balance sheets.

	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Long-term debt obligations(1)	$	322,462	$	2,305	$	7,545	$	312,612	$	—
Third-party drilling rig agreements(2)	1,115		1,115		—		—		—
Asset retirement obligations	106,481		66,154		6,785		5,395		28,147
Operating leases and other(3)	18,187		5,650		7,437		900		4,200
Total	$	448,245	$	75,224	$	21,767	$	318,907	$	32,347

____________________

(1) Includes interest on long-term debt (if any) in the years which it will be incurred, and assumes debt principal amounts are outstanding until their latest contractual maturity, with no additional conversions of New Convertible Notes to common stock.

(2) 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.

(3) Includes the obligation for employee and employer match contributions to the participants of our non-qualified deferred compensation plan for eligible highly compensated employees who elect to defer income exceeding the Internal Revenue Service (“IRS”) annual limitations on qualified 401(k) retirement plans.

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Valuation Allowance

In 2008 and 2009, the Predecessor Company recorded full cost ceiling impairments totaling $3.5 billion on its oil and natural gas assets, resulting in the Company being in a net deferred tax asset position. Management 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 the Company’s net deferred tax asset in the period ending December 31, 2008. This valuation allowance was maintained for the Predecessor Company since 2008. Upon Emergence, the Company’s tax basis in property, plant, and equipment was not significantly impacted by the restructuring and exceeded the book carrying value of its assets at October 1, 2016. Additionally, the Company has a significant U.S. Federal net operating loss of approximately $1.3 billion remaining after the attribute reduction caused by the restructuring transactions. As such, the Successor Company has significant deferred tax assets to consume. See “Note 18—Income Taxes” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the impact of the restructuring transactions on the Company’s tax attributes.

Management considered all available evidence in determining whether to establish a valuation allowance on its net deferred tax asset upon emergence and maintain such valuation allowance for the period ending December 31, 2016. Factors considered are, but not limited to, the reversal periods of existing deferred tax liabilities and deferred tax assets, the historical earnings of the Company and the prospects of future earnings. For purposes of the valuation allowance analysis, “earnings” is defined as pre-tax earnings as adjusted for permanent tax adjustments.

The Company experienced losses and was in a cumulative negative earnings position leading up to the petition date for Chapter 11. Further, the Company has a presumption of cumulative negative earnings upon emergence and experienced negative earnings for the Successor 2016 Period ending December 31, 2016. The existence of or presumption of cumulative negative earnings is not a definitive factor in a determination to establish or maintain a valuation allowance as all available evidence should be considered, however it is a significant piece of negative evidence in management’s analysis.

The Company’s revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Relatively modest drops in prices can significantly affect the Company’s financial results and impede its growth. Changes in oil and natural gas prices have a significant impact on the value of the Company’s reserves and on its cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control. Due to these factors, management has placed a lower weight on the prospects of future earnings in its overall analysis of the valuation allowance for the Successor Company at both emergence and for the period ended December 31, 2016.

In determining whether to establish a valuation allowance upon emergence and maintain the valuation allowance at December 31, 2016, management concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual negative earnings for the period ending December 31, 2016, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, management concluded that it was more likely than not that the Company will not realize a future benefit from certain of the deferred tax assets identified and accordingly placed a full valuation allowance to offset its net deferred tax asset upon emergence. Management has not changed its judgment regarding the need for a full valuation allowance against its net deferred tax asset for the period ending December 31, 2016 for the same reasons. The valuation allowance against the Company’s net deferred tax asset at December 31, 2016 was $1.0 billion. The Predecessor Company’s net deferred tax asset position and corresponding valuation allowance was $1.9 billion and $0.6 billion at December 31, 2015 and December 31, 2014, respectively.

Additionally, at December 31, 2016, the Company has valuation allowances totaling $95.8 million against specific deferred tax assets for which management has determined it is more likely than not that such deferred tax assets will not be realized for various reasons. The valuation allowance against these specific deferred tax assets may not be impacted by a change in judgment with respect to the analysis of the Company’s valuation allowance against its net deferred tax asset.

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Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company’s financial statements requires the Company to make assumptions and prepare estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Company bases its estimates on historical experience and various other assumptions that the Company believes are reasonable; however, actual results may differ significantly. The Company’s critical accounting policies and additional information on significant estimates used by the Company are discussed below. See “Note 3—Summary of Significant Accounting Policies” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the Company’s 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 Company allocated the reorganization value of the Company 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 will not be 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 with specific hedge accounting criteria having been met. 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 94.0% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2016. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control. Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and 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, 2016, 2015 and 2014, the Company revised its proved reserves from prior years’ reports by approximately (105.4) MMBoe, (234.6) MMBoe and 20.3 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

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within the original field boundaries. Estimates of proved reserves are key components of the Company’s most significant financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect the Company’s future depreciation, depletion and impairment expenses. As part of fresh start accounting, proved reserves were adjusted to their estimated fair value as of October 1, 2016, as described in “Note 2—Fresh Start Accounting.”

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 present value of future net revenues from proved oil, natural gas and NGL reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less related tax effects (the “ceiling limitation”). The Company calculates its full cost ceiling limitation using the 12-month average oil and natural gas prices for the most recent 12 months as of the balance sheet date and adjusted for basis or location differential, 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 a 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, $4.5 billion and $164.8 million for the period from January 1, 2016 through October 1, 2016, and the years ended December 31, 2015, and 2014, respectively. 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. The Company estimates that substantially all of its costs classified as unproved as of the balance sheet date will be evaluated and transferred within a 10-year period from the date of acquisition, contingent on the Company’s capital expenditures and drilling program. As part of fresh start accounting, proved reserves were adjusted to their estimated fair value as of October 1, 2016, as described in “Note 2—Fresh Start Accounting.”

Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. 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 10 to 39 years for buildings and 2 to 30 years

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for 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. 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 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. As part of fresh start accounting, property, plant and equipment were adjusted to their estimated fair value and depreciable lives were revised as of October 1, 2016, as described in “Note 2—Fresh Start Accounting.”

See “—Consolidated Results of Operations” and “Note 9—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 rates 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. Oil, natural gas and NGL revenues are recorded when title of production sold passes to the customer, net of royalties, discounts and allowances, as applicable. The Successor Company has made an accounting policy election to deduct transportation costs from oil, natural gas and NGL revenues. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

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, 2016, the Company had a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.

New Accounting Pronouncements. For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 3—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 management’s 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 received. The New First Lien Exit 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, 2016, our commodity derivative contracts consisted of fixed price swaps, under which the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month or quarter of the contract period, and 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. Settlement for oil derivative contracts occurs in the succeeding month or quarter and natural gas derivative contracts are settled in the production month or quarter.

At December 31, 2016, our open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2017 - December 2017	3,285	$	52.24
January 2018 - December 2018	1,825	$	55.34

Natural Gas Price Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2017 - December 2017	32,850	$	3.20
January 2018 - December 2018	3,650	$	3.12

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 future prices as of period-end compared to the contract price.

We recorded a 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 related to early settlements of commodity derivative contracts in the second quarter of 2016 after the Chapter 11 filings occurred.

We recorded gains on commodity derivative contracts of $73.1 million and $334.0 million for the years ended December 31, 2015 and 2014, respectively, as reflected in the consolidated statements of operations in Item 8 of this report, which includes net cash (receipts) payments upon settlement of $(327.7) million and $32.3 million, respectively. Included in the net cash payments for 2014 are $69.6 million of cash payments related to early settlements primarily as a result of the sale of the Gulf Properties in February 2014.

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See “Note 12—Derivatives” to the consolidated financial statements in Item 8 of this report for additional information regarding the Company’s 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 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 in the second quarter of 2016 and prior to their contractual maturities 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 remaining 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 New First Lien Exit Facility or subsequently, the refinanced credit facility, can be offset against amounts owed, if any, to such counterparty. As of December 31, 2016, the counterparties to our open commodity derivative contracts were all also lenders under the First Lien Exit Facility. As a result, we were not required to post additional collateral under our commodity derivative contracts.

Interest Rate Risk. We are exposed to interest rate risk on our variable rate debt. Variable rate debt, where the interest rate fluctuates, exposes us to short-term changes in market interest rates as our interest obligations on these instruments are 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, 2016.

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Item 8.        Financial Statements and Supplementary Data

The Company’s consolidated financial statements required by this item are included in this report beginning on page F-1.

72

Item 9.        Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

73

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, 2016 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, 2016 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

74

Item 9B.    Other Information

Not Applicable.

75

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 May 1, 2017: “Director Biographical Information,” “Executive Officers,” “Compliance with Section 16(a) of the Exchange Act” and “Corporate Governance Matters.”

76

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 May 1, 2017: “Director Compensation,” “Outstanding Equity Awards” and “Executive Officers and Compensation.”

77

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 May 1, 2017: “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management.”

78

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 May 1, 2017: “Related Party Transactions” and “Corporate Governance Matters.”

79

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 May 1, 2017.

80

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 F-1.

(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

81

Item 16.    Form 10-K Summary

Not Applicable.

82

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page(s)
Management’s Report on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets at December 31, 2016 and 2015	F-5
Consolidated Statements of Operations for the Period from October 2, 2016 through December 31, 2016, the Period from January 1, 2016 through October 1, 2016 and the Years Ended December 31, 2015 and 2014	F-7
Consolidated Statements of Changes in Stockholders’ Equity for the Period from October 2, 2016 through December 31, 2016, the Period from January 1, 2016 through October 1, 2016 and the Years Ended December 31, 2015 and 2014	F-8
Consolidated Statements of Cash Flows for the Period from October 2, 2016 through December 31, 2016, the Period from January 1, 2016 through October 1, 2016 and the Years Ended December 31, 2015 and 2014	F-10
Notes to Consolidated Financial Statements	F-11

F-1

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, 2016. 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, 2016.

/s/    JAMES D. BENNETT	/s/    JULIAN BOTT
James D. Bennett President and Chief Executive Officer	Julian Bott Executive Vice President and Chief Financial Officer

F-2

Report of Independent Registered Public Accounting Firm

To theBoard of Directors and Stockholders of SandRidge Energy, Inc.

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, changes in stockholders’ equity and cash flows present fairly, in all material respects, the financial position of SandRidge Energy, Inc. and its subsidiaries (Successor Company) as of December 31, 2016 and the results of their operations and their cash flows for the period from October 2, 2016 to December 31, 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 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, 2016and 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, 2016and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, theCompany adopted fresh start accounting as of October 1, 2016.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

March 3, 2017

F-3

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, changes in stockholders’ equity and cash flows present fairly, in all material respects, the financial position of SandRidge Energy, Inc. and its subsidiaries (Predecessor Company) as of December 31, 2015 and the results of their operations and their cash flows for the period from January 1, 2016 to October 1, 2016, and for each of the two years in the period ended December 31, 2015 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 audits. We conducted our audits 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 audits provide 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, 2016and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, theCompany adopted fresh start accounting.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

March 3, 2017

F-4

SandRidge Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except per share data)

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
ASSETS
Current assets
Cash and cash equivalents	$	121,231		$	435,588
Restricted cash - collateral	50,000			—
Restricted cash - other	2,840			—
Accounts receivable, net	74,097			127,387
Derivative contracts	—			84,349
Prepaid expenses	5,375			6,833
Other current assets	3,633			19,931
Total current assets	257,176			674,088
Oil and natural gas properties, using full cost method of accounting
Proved (includes development and project costs excluded from amortization of $16.7 million and $34.6 million at December 31, 2016 and 2015, respectively)	840,201			12,529,681
Unproved	74,937			363,149
Less: accumulated depreciation, depletion and impairment	(353,030		)	(11,149,888		)
	562,108			1,742,942
Other property, plant and equipment, net	255,824			491,760
Other assets	6,284			13,237
Total assets	$	1,081,392		$	2,922,027

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

F-5

SandRidge Energy, Inc., and Subsidiaries

Consolidated Balance Sheets—Continued

(In thousands, except per share data)

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	116,517		$	428,417
Derivative contracts	27,538			573
Asset retirement obligations	66,154			8,399
Other current liabilities	3,497			—
Total current liabilities	213,706			437,389
Long-term debt	305,308			3,562,378
Derivative contracts	2,176			—
Asset retirement obligations	40,327			95,179
Other long-term obligations	6,958			14,814
Total liabilities	568,475			4,109,760
Commitments and contingencies (Note 14)
Equity
SandRidge Energy, Inc. stockholders’ equity (deficit)
Predecessor preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015; aggregate liquidation preference of $265,000	—			3
7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000	—			3
Predecessor common stock, $0.001 par value; 1,800,000 shares authorized, 635,584 issued and 633,471 outstanding at December 31, 2015	—			630
Predecessor additional paid-in capital	—			5,301,136
Predecessor additional paid-in capital—stockholder receivable	—			(1,250		)
Predecessor treasury stock, at cost	—			(5,742		)
Successor common stock, $0.001 par value; 250,000 shares authorized; 21,042 issued and 19,635 outstanding at December 31, 2016	20			—
Successor warrants	88,381			—
Successor additional paid-in capital	758,498			—
Accumulated deficit	(333,982		)	(6,992,697		)
Total SandRidge Energy, Inc. stockholders’ equity (deficit)	512,917			(1,697,917		)
Noncontrolling interest	—			510,184
Total stockholders’ equity (deficit)	512,917			(1,187,733		)
Total liabilities and stockholders’ equity (deficit)	$	1,081,392		$	2,922,027

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

F-6

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

For the Period from October 2, 2016 through December 31, 2016, the Period from January 1, 2016 through October 1, 2016 and the Years Ended December 31, 2015 and 2014

(In thousands, except per share amounts)

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Revenues
Oil, natural gas and NGL	$	98,307		$	279,971		$	707,434		$	1,420,879
Other	149			13,838			61,275			137,879
Total revenues	98,456			293,809			768,709			1,558,758
Expenses
Production	24,997			129,608			308,701			346,088
Production taxes	2,643			6,107			15,440			31,731
Depreciation and depletion—oil and natural gas	33,971			86,613			319,913			434,295
Depreciation and amortization—other	3,922			21,323			47,382			59,636
Accretion of asset retirement obligations	2,090			4,365			4,477			9,092
Impairment	319,087			718,194			4,534,689			192,768
General and administrative	9,837			116,091			137,715			113,991
Employee termination benefits	12,334			18,356			12,451			8,874
Loss (gain) on derivative contracts	25,652			4,823			(73,061		)	(334,011		)
Loss on settlement of contract	—			90,184			50,976			—
Other operating expenses	268			4,348			52,704			106,070
Total expenses	434,801			1,200,012			5,411,387			968,534
(Loss) income from operations	(336,345		)	(906,203		)	(4,642,678		)	590,224
Other (expense) income
Interest expense	(372		)	(126,099		)	(321,421		)	(244,109		)
Gain on extinguishment of debt	—			41,179			641,131			—
Gain on reorganization items, net	—			2,430,599			—			—
Other income, net	2,744			1,332			2,040			3,490
Total other income (expense)	2,372			2,347,011			321,750			(240,619		)
(Loss) income before income taxes	(333,973		)	1,440,808			(4,320,928		)	349,605
Income tax expense (benefit)	9			11			123			(2,293		)
Net (loss) income	(333,982		)	1,440,797			(4,321,051		)	351,898
Less: net (loss) income attributable to noncontrolling interest	—			—			(623,506		)	98,613
Net (loss) income attributable to SandRidge Energy, Inc.	(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	$	(333,982	)	$	1,424,476		$	(3,735,495	)	$	203,260
(Loss) earnings per share
Basic	$	(17.61	)	$	2.01		$	(7.16	)	$	0.42
Diluted	$	(17.61	)	$	2.01		$	(7.16	)	$	0.42
Weighted average number of common shares outstanding
Basic	18,967			708,928			521,936			479,644
Diluted	18,967			708,928			521,936			499,743

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

F-7

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (Deficit)

For the Period from October 2, 2016 through December 31, 2016, the Period from January 1, 2016 through October 1, 2016 and the Years Ended December 31, 2015 and 2014

	Convertible Perpetual Preferred Stock					Common Stock					Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	Shares		Amount			Shares		Amount
	(In thousands)
Balance at December 31, 2013 - Predecessor	7,650		$	8		490,290		$	483		$	5,294,551		$	(8,770	)	$	(3,460,462	)	$	1,349,817		$	3,175,627
Sale of royalty trust units	—		—			—		—			4,091			—			—			18,028			22,119
Distributions to noncontrolling interest owners	—		—			—		—			—			—			—			(193,807		)	(193,807		)
Purchase of treasury stock	—		—			—		—			—			(6,373		)	—			—			(6,373		)
Retirement of treasury stock	—		—			—		—			(6,373		)	6,373			—			—			—
Stock distributions, net of purchases - retirement plans	—		—			206		—			(1,781		)	1,790			—			—			9
Stock-based compensation	—		—			—		—			23,665			—			—			—			23,665
Stock-based compensation excess tax provision	—		—			—		—			14			—			—			—			14
Payment received on shareholder receivable	—		—			—		—			1,250			—			—			—			1,250
Issuance of restricted stock awards, net of cancellations	—		—			3,311		3			(3		)	—			—			—			—
Acquisition of ownership interest	—		—			—		—			(2,074		)	—			—			(656		)	(2,730		)
Repurchase of common stock	—		—			(27,411	)	(27		)	(111,800		)	—			—			—			(111,827		)
Conversion of 6% preferred stock	(2,000	)	(2		)	18,423		18			(16		)	—			—			—			—
Net income	—		—			—		—			—			—			253,285			98,613			351,898
Convertible perpetual preferred stock dividends	—		—			—		—			—			—			(50,025		)	—			(50,025		)
Balance at December 31, 2014 - Predecessor	5,650		6			484,819		477			5,201,524			(6,980		)	(3,257,202		)	1,271,995			3,209,820
Distributions to noncontrolling interest owners	—		—			—		—			—			—			—			(138,305		)	(138,305		)
Purchase of treasury stock	—		—			—		—			—			(2,428		)	—			—			(2,428		)
Retirement of treasury stock	—		—			—		—			(2,428		)	2,428			—			—			—
Stock distributions, net of purchases - retirement plans	—		—			(1,000	)	—			(916		)	1,238			—			—			322
Stock-based compensation	—		—			—		—			21,123			—			—			—			21,123
Payment received on shareholder receivable	—		—			—		—			1,250			—			—			—			1,250
Issuance of restricted stock awards, net of cancellations	—		—			1,514		5			(5		)	—			—			—			—
Common stock issued for debt	—		—			120,881		121			63,178			—			—						63,299
Conversion of preferred stock to common stock	(230	)	—			2,968		3			(3		)	—			—			—			—
Net loss	—		—			—		—			—			—			(3,697,545		)	(623,506		)	(4,321,051		)
Convertible perpetual preferred stock dividends	—		—			24,289		24			16,163			—			(37,950		)	—			(21,763		)
Balance at December 31, 2015 - Predecessor	5,420		$	6		633,471		$	630		$	5,299,886		$	(5,742	)	$	(6,992,697	)	$	510,184		$	(1,187,733	)

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

F-8

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (Deficit)—Continued

For the Period from October 2, 2016 through December 31, 2016, the Period from January 1, 2016 through October 1, 2016 and Years Ended December 31, 2015 and 2014

	Convertible Perpetual Preferred Stock					Common Stock					Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	Shares		Amount			Shares		Amount
	(In thousands)
Balance at December 31, 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		)
Purchase of treasury stock	—		—			—		—			—			(44		)	—			—			(44		)
Retirement of treasury stock	—		—			—		—			(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	—		$	—		—		$	—		$	—		$	—		$	—		$	—		$	—

	Common Stock			Warrants				Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Total
	Shares	Amount		Shares	Amount
	(In thousands)
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 - Predecessor	18,932	$	19	6,442	$	88,382		$	739,023		$	—		$	—		$	827,424
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
Purchase of treasury stock	—	—		—	—			—			(110		)	—			(110		)
Retirement of treasury stock	—	—		—	—			(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

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

F-9

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

For the Period from October 2, 2016 through December 31, 2016, the Period from January 1, 2016 through October 1, 2016 and the Years Ended December 31, 2015 and 2014

(In thousands)

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(333,982	)	$	1,440,797		$	(4,321,051	)	$	351,898
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities
Provision for doubtful accounts	(13,166		)	16,704			—			—
Depreciation, depletion and amortization	37,893			107,936			367,295			493,931
Accretion of asset retirement obligations	2,090			4,365			4,477			9,092
Impairment	319,087			718,194			4,534,689			192,768
Gain on reorganization items, net	—			(2,442,436		)	—			—
Debt issuance costs amortization	—			4,996			11,884			9,425
Amortization of discount, net of premium, on debt	(81		)	2,734			3,130			529
Gain on extinguishment of debt	—			(41,179		)	(641,131		)	—
Write off of debt issuance costs	—			—			7,108			—
(Gain) loss on debt derivatives	—			(1,324		)	10,377			—
Cash paid for early conversion of convertible notes	—			(33,452		)	(32,741		)	—
Loss (gain) on derivative contracts	25,652			4,823			(73,061		)	(334,011		)
Cash received on settlement of derivative contracts	7,698			72,608			327,702			11,796
Loss on settlement of contract	—			90,184			50,976			—
Cash paid on settlement of contract	—			(11,000		)	(24,889		)	—
Stock-based compensation	6,250			9,075			18,380			19,994
Other	717			(3,260		)	2,842			417
Changes in operating assets and liabilities increasing (decreasing) cash
Deconsolidation of noncontrolling interest	—			(9,654		)	—			—
Receivables	12,872			36,116			201,907			(63,492		)
Prepaid expenses	(1,079		)	(5,681		)	1,148			9,549
Other current assets	(260		)	(181		)	12,710			3,164
Other assets and liabilities, net	1,505			(7,542		)	2,239			(1,132		)
Accounts payable and accrued expenses	990			(61,305		)	(86,470		)	(66,492		)
Asset retirement obligations	(591		)	(3,595		)	(3,984		)	(16,322		)
Net cash provided by (used in) operating activities	65,595			(112,077		)	373,537			621,114
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(51,676		)	(186,452		)	(879,201		)	(1,553,332		)
Acquisitions of assets	—			(1,328		)	(216,943		)	(18,384		)
Proceeds from sale of assets	11,841			20,090			56,504			714,475
Net cash used in investing activities	(39,835		)	(167,690		)	(1,039,640		)	(857,241		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	—			489,198			2,065,000			—
Repayments of borrowings	(414,954		)	(74,243		)	(939,466		)	—
Debt issuance costs	—			(333		)	(53,244		)	(3,947		)
Proceeds from building mortgage	—			26,847			—			—
Payment of mortgage proceeds and cash recovery to debt holders	—			(33,874		)	—			—
Proceeds from the sale of royalty trust units	—			—			—			22,119
Noncontrolling interest distributions	—			—			(138,305		)	(193,807		)
Purchase of treasury stock	(110		)	(44		)	(3,535		)	(8,702		)
Repurchase of common stock	—			—			—			(111,827		)
Dividends paid—preferred	—			—			(11,262		)	(55,525		)
Cash paid on settlement of financing derivative contracts	—			—			—			(44,128		)
Other	3			—			1,250			(1,466		)
Net cash (used in) provided by financing activities	(415,061		)	407,551			920,438			(397,283		)
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH	(389,301		)	127,784			254,335			(633,410		)
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	563,372			435,588			181,253			814,663
CASH, CASH EQUIVALENTS and RESTRICTED CASH end of year	$	174,071		$	563,372		$	435,588		$	181,253

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

F-10

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1. Voluntary Reorganization under Chapter 11 Proceedings

On May 16, 2016, the Company and certain of its direct and indirect subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016 (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 “Plan”), 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 secured revolving credit facility (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 reserve-based revolving credit facility (the “New First Lien Exit Facility”). Refer to Note 11 for additional information.

• Cash Collateral Account. The Company deposited $50.0 million of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i) $12.5 million will be released to the Company upon delivery of an acceptable business plan to the administrative agent, (ii) $12.5 million will be released to the Company upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to the Company, up to $25.0 million will be released to the Company upon meeting a minimum 2.00:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017.

If no default or event of default under the New First Lien Exit Facility exists at the expiration or termination of the Protected Period, all remaining proceeds in the Cash Collateral Account will be released to the Company at that time.

• Senior Secured Notes. All outstanding obligations under the 8.75% Senior Secured Notes due 2020 issued in June 2015 and the $78.0 million principal 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC (“PGC) in October 2015, (the “PGC Senior Secured Notes”) (collectively, “Senior Secured Notes”) were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of common stock in the Successor Company (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal amount of newly issued, non-interest bearing 0.00% convertible senior subordinated notes due 2020, (the “New Convertible Notes”), which are mandatorily convertible into approximately 15.0 million shares of New Common Stock upon the first to occur of several triggering events, one of which is refinancing of the New First Lien Exit Facility. Refer to Note 11 and Note 15 for additional information.

• General Unsecured Claims.The Company’s general unsecured claims, including 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 (collectively, the “Senior Unsecured Notes”) and the 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, 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 New 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

F-11

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

issued immediately upon emergence, with initial exercise prices of $41.34 and $42.03 per share, respectively, which expire on October 4, 2022, (the “Warrants”). Refer to Note 11 and Note 15 for additional information.

• New Building Note. A note with a principal amount of $35.0 million, which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) 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 Unsecured Senior Notes. Refer to Note 11 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. Refer to Note 15 for additional information.

Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company’s post-emergence board of directors is comprised of five directors, including the Company’s Chief Executive Officer, James Bennett, and four non-employee directors, Michael L. Bennett, John V. Genova, William “Bill” M. Griffin, Jr. and David J. Kornder.

2. Fresh Start Accounting

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.

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, fresh start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2016 and related fresh start adjustments are included in the accompanying statement of operations for the period from January 1, 2016 through October 1, 2016 (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 period after October 1, 2016 (the “Successor 2016 Period”) will not be 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.

Reorganization Value. Reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate 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 is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s 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 $1.04 billion to $1.32 billion, which was subsequently approved by the Bankruptcy Court. 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. Based on the estimates and assumptions used in determining the enterprise value, the Company estimated the enterprise value to be approximately $1.09 billion.

Valuation of Oil and Gas Properties. The Company’s principal assets are its oil and gas properties, which are accounted for under the Full Cost Accounting method as described in Note 3. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.

The fair value analysis performed by valuation experts was based on the Company’s estimates of proved reserves as developed internally by the Company’s reserves engineers. Discounted cash flow models were prepared using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising the proved reserves. Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company. Development and operating costs from proved reserves estimates were adjusted for inflation. A risk adjustment factor was applied to the proved undeveloped reserve category. The discounted cash flow models also included estimates not

F-12

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

typically included in proved reserves such as depreciation and income tax expenses.

The risk adjusted after tax cash flows were discounted at 10%. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants.

From this analysis the Company concluded the fair value of its proved reserves was $632.8 million as of the Emergence Date. The Company also reviewed its undeveloped leasehold acreage and concluded that the fair value of undeveloped leasehold acreage was $113.9 million based on analysis of comparable market transactions. These amounts are reflected in the Fresh Start Adjustments item number 14 below.

The following table reconciles the enterprise value to the estimated fair value of the Successor Company's common stock as of the Emergence Date (in thousands, except per share amounts):

Enterprise value	$	1,089,808
Plus: Cash and cash equivalents	563,372
Less: Fair value of New Building Note	(36,610		)
Less: Asset retirement obligation	(92,412		)
Less: Fair value of New First Lien Exit Facility	(414,954		)
Less: Fair value of New Convertible Notes	(445,660		)
Less: Fair value of warrants, including warrants held in reserve for settlement of general unsecured claims	(95,794		)
Fair value of Successor common stock issued upon emergence	$	567,750
Shares issued upon emergence on October 4, 2016, including shares held in reserve for settlement of general unsecured claims	19,371
Per share value	$	29.31

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 equivalents	563,372
Plus: other working capital liabilities	131,766
Plus: other long-term liabilities	8,549
Reorganization value of Successor assets	$	1,793,495

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.

Consolidated Balance Sheet. The adjustments included in the following consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company on the Emergence Date (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.

F-13

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

The following table reflects the reorganization and application of Accounting Standards Codification (“ASC”) 852 “Reorganizations” on the consolidated balance sheet as of October 1, 2016 (in thousands):

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
ASSETS
Current assets
Cash and cash equivalents	$	652,680		$	(142,148	)	(1)	$	—			$	510,532
Restricted cash - collateral	—			50,000			(2)	—				50,000
Restricted cash - other	—			2,840			(2)	—				2,840
Accounts receivable, net	61,446			12,356			(3)	—				73,802
Derivative contracts	10,192			—				(669		)	(12)	9,523
Prepaid expenses	12,514			(8,218		)	(4)	—				4,296
Other current assets	1,003			—				3,217			(13)	4,220
Total current assets	737,835			(85,170		)		2,548				655,213
Oil and natural gas properties, using full cost method of accounting
Proved	12,093,492			—				(11,344,684		)	(14)	748,808
Unproved	322,580			—				(205,578		)	(14)	117,002
Less: accumulated depreciation, depletion and impairment	(11,637,538		)	—				11,637,538			(14)	—
	778,534			—				87,276				865,810
Other property, plant and equipment, net	357,528			(41		)		(93,782		)	(15)	263,705
Derivative contracts	70			—				(70		)	(12)	—
Other assets	12,537			(3,770		)	(5)	—				8,767
Total assets	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

F-14

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	140,448		$	(14,820	)	(6)	$	—			$	125,628
Derivative contracts	2,982			—				1,666			(12)	4,648
Asset retirement obligations	8,573			—				57,105			(16)	65,678
Total current liabilities	152,003			(14,820		)		58,771				195,954
Long-term debt	—			731,735			(7)	1,610			(17)	733,345
Derivative contracts	935			—				304			(12)	1,239
Asset retirement obligations	62,896			—				(36,161		)	(16)	26,735
Other long-term obligations	3			8,798			(8)	(3		)		8,798
Liabilities subject to compromise	4,346,188			(4,346,188		)	(9)	—				—
Total liabilities	4,562,025			(3,620,475		)		24,521				966,071
Equity
SandRidge Energy, Inc. stockholders’ equity (deficit)
Predecessor preferred stock	6			—				(6		)	(18)	—
Predecessor common stock	718			—				(718		)	(18)	—
Predecessor additional paid-in capital	5,315,655			—				(5,315,655		)	(18)	—
Predecessor additional paid-in capital—stockholder receivable	(1,250		)	1,250			(10)	—				—
Predecessor treasury stock, at cost	(5,218		)	—				5,218			(18)	—
Successor common stock	—			19			(11)	—				19
Successor warrants	—			88,382			(11)	—				88,382
Successor additional paid-in capital	—			739,023			(11)	—				739,023
Accumulated deficit	(7,985,411		)	2,702,820			(9)	5,282,591			(19)	—
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	(2,675,500		)	3,531,494				(28,570		)		827,424
Noncontrolling interest	(21		)	—				21			(20)	—
Total stockholders’ (deficit) equity	(2,675,521		)	3,531,494				(28,549		)		827,424
Total liabilities and stockholders’ equity (deficit)	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

Reorganization Adjustments

1. Reflects the net cash payments made upon emergence (in thousands):

Sources:
Proceeds from New Building Note	$	26,847
Total sources	$	26,847
Uses and transfers:
Cash transferred to restricted accounts (collateral and general unsecured claims)	$	52,840
Payments and funding of escrow account related to professional fees	43,770
Payment on Senior Credit facility (principal and interest)	35,238
Repayment of Senior Secured Notes and Unsecured Notes	33,874
Payment of certain contract cures and other	3,273
Total uses and transfers	168,995
Net uses and transfers	$	(142,148	)

F-15

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

2. Funding of $50.0 million Cash Collateral account and the funding of $2.8 million to be held in reserve by the Company for distribution to satisfy allowed general unsecured claims as specified under the Plan.

3. Accrual for future reimbursement of the unused portion of the professional fees escrow account and other receivables.

4. Write-off of prepaid expenses primarily related to $7.5 million of prepaid premium for the Predecessor Company’s directors and officers insurance policy.

5. Application of a $3.8 million deposit held by a utility service toward the settlement of the utility service’s claims under the Plan.

6. Includes a $43.8 million decrease in accrued liabilities as a result of funding an escrow account established for the payment of professional fees, partially offset by the reinstatement of certain liabilities subject to compromise as accounts payable and accrued expenses.

7. Principal balances of $35.0 million of the New Building Note, $281.8 million of the New Convertible Notes, and the $415.0 million drawn on the New First Lien Exit Facility.

8. Reclassification of non-qualified deferred compensation plan and gas balancing liabilities from liabilities subject to compromise to other long term obligations, as these liabilities became obligations of the Successor.

9. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):

Current maturities of long-term debt and accrued interest	$	4,179,483
Accounts payable and accrued expenses	157,422
Other long-term liabilities	9,283
Liabilities subject to compromise of the Predecessor	4,346,188
Cash payments at emergence	(72,385		)
Cash proceeds from building mortgage	26,847
Write-off of prepaid accounts upon emergence	(8,218		)
Accrual for future reimbursement from professional fees escrow account and other receivables	12,356
Total consideration given pursuant to the Plan:
Fair value of equity issued	(827,424		)
Principal value of long-term debt issued and reinstated at emergence	(731,735		)
Reinstatement of liabilities subject to compromise as accounts payable and accrued expenses	(37,789		)
Release of stockholder receivable	(1,250		)
Application of deposit held by utility services	(3,770		)
Gain on settlement of liabilities subject to compromise	$	2,702,820

10. Release of a receivable from the Predecessor’s former director and officer as outlined in the Plan.

F-16

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

11. The following table reconciles reorganization adjustments made to Successor common stock, warrants and additional paid in capital (in thousands):

Par value of 18.9 million shares of New Common Stock issued to former holders of the Senior Secured Notes and Unsecured Notes (valued at $29.31 per share)	$	19
Fair value of warrants issued to holders of the Unsecured Notes(1)	88,382
Additional paid in capital - New Common Stock	575,144
Additional paid in capital - premium on New Convertible Notes(2)	163,879
Total Successor Company equity issued on Emergence Date	$	827,424

____________________

(1) The fair value of the warrants was estimated using a Black-Scholes-Merton model with the following assumptions: implied stock price of the Successor Company; exercise price per share of $41.34 and $42.03 for Warrant classes A and B, respectively; expected volatility of 59.26%; risk free interest rate, continuously compounded, of 1.36%; and holding period of six years.

(2) The fair value of the New Convertible Notes was estimated using a Monte Carlo simulation with the following assumptions; the implied Successor Company stock price; expected volatility of 56.06%; risk free interest rate, continuously compounded, of 1.08%; recovery rate of 15.00%; hazard rate of 12.41%; drop on default of 100.00%; and termination period after four years. The premium is the difference between the fair value of the New Convertible Notes of $445.7 million and the principal value of the New Convertible Notes of $281.8 million.

Fresh Start Adjustments

12. Adjustments and reclassifications of derivative contracts based on their Emergence Date fair values, which were determined using the fair value methodology for commodity derivative contracts discussed in Note 6.

13. Fair value adjustment to other current assets to record assets held for sale at their anticipated sales prices.

14. Fair value adjustments to oil and natural gas properties, including asset retirement obligation, associated inventory, unproved acreage and seismic. See above for detailed discussion of fair value methodology.

15. Adjustments to other property, plant and equipment to record the assets at their respective fair values on the Emergence Date. A combination of the cost approach and income approach were utilized to determine the fair values of the Company’s headquarters and other properties located in downtown Oklahoma City, Oklahoma, and the cost approach was utilized to determine the fair value of all other property, plant and equipment.

16. Fair value adjustments to the Company’s asset retirement obligations as a result of applying fresh start accounting. Upon implementation of fresh start accounting, the Company revalued these obligations based upon updates to wells’ productive lives and application of the Successor Company’s credit adjusted risk fee rate.

17. Fair value adjustment to record premium on the New Building Note.

18. Cancellation of Predecessor Company’s common stock, preferred stock, treasury stock and paid-in capital.

19. Adjustment to reset retained deficit to zero.

20. Elimination of the Predecessor non-controlling interest.

F-17

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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 settlements	84,228
Loss on mortgage	(8,153		)
Gain on preferred stock dividends	37,893
Fresh start valuation adjustments	(28,549		)
Fair value of equity issued	(827,424		)
Principal value of New Convertible Notes issued	(281,780		)
Gain on reorganization items, net	$	2,430,599

3. Summary of Significant Accounting Policies

Fresh Start Accounting. Upon emergence from bankruptcy the Company adopted fresh start accounting. See Note 2 for further details.

Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent and Rockies regions of the United States. The Company’s Rockies properties were acquired during the fourth quarter of 2015. Additionally, the Company owned interests in the Gulf of Mexico and Gulf Coast until February 2014, as discussed in Note 5.

Principles of Consolidation. The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and satisfaction of liabilities in the normal course of business. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. During the years ended December 31, 2015, and 2014, the Company fully consolidated the activities of each the SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Mississippian Trust II (the “Mississippian Trust II”) and SandRidge Permian Trust (the “Permian Trust”) (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) as variable interest entities (“VIEs”) for which the Company was the primary beneficiary. Activities of the Royalty Trusts attributable to third party ownership were presented as noncontrolling interest and included as a component of equity in the condensed consolidated balance sheet as of December 31, 2015. As discussed further below, during the year ended December 31, 2016, the Company proportionately consolidated the activities of the Royalty Trusts. All significant intercompany accounts and transactions have been eliminated in consolidation.

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 natural gas liquids (“NGL”) reserves; impairment tests of long-lived assets; 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.

F-18

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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 Companymaintains 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 exploration, production and treating services for 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 collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. As part of fresh start accounting, the allowance for doubtful accounts was reset to zero on the Emergence Date. Refer to Note 7 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, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 6 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 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. Fair value measurements for the electrical asset were based on replacement cost. Inputs used in the cost approach are based on the cost to a market participant buyer to acquire or construct a substitute asset of comparable utility, adjusted for inutility. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 6.

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.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. 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 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 12 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 Company capitalized internal costs during the Successor 2016 Period of $4.0 million and the Predecessor Company capitalized internal costs of $22.7 million, $45.1 million and $55.4 million to the full cost pool during the Predecessor 2016 Period and the years ended December 31, 2015 and 2014, respectively. Capitalized costs are amortized using the unit-of-production method. Under this

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. 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.

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 an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. 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 drilling equipment, natural gas gathering and treating equipment, electrical infrastructure, transportation equipment and other property and equipment are carried at cost. 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 10 to 39 years for buildings and 2 to 30 years for equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. As part of fresh start accounting, property, plant and equipment were adjusted to their estimated fair value and depreciable lives were revised as of October 1, 2016, as described in Note 2.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 9 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 Predecessor 2016 Period and years ended December 31, 2015 and 2014, the Predecessor Company capitalized interest of approximately, $2.2 million, $10.8 million and $14.7 million,

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

respectively, on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally, the Predecessor Company capitalized interest of $3.3 million and $5.0 million in 2015 and 2014, respectively, on midstream and corporate assets which were under construction.

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 scheduled maturity period of the related debt. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.

Investments. Investments in marketable equity securities relate primarily to the Company’s non-qualified deferred compensation plan, and have been designated as available for sale and measured at fair value using quoted prices readily available in the market pursuant to the 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 sheets.

Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, 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 well is sold, at which time 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 rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 13 for further discussion of the Company’s asset retirement obligations. As part of fresh start accounting, the ARO liabilities were adjusted to their estimated fair value as described in Note 2.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company has made an accounting policy election to deduct transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $7.4 million of transportation costs as a reduction from revenues in the Successor 2016 Period versus the presentation of $26.2 million, $45.3 million and $35.6 million of these costs as production expenses in the Predecessor 2016 Period, and the years ended December 31, 2015 and 2014, respectively. and Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $1.7 million and $1.5 million at December 31, 2016 and 2015, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

For the years ended December 31, 2015 and 2014, the Company recognized revenues and expenses generated from daywork and footage drilling contracts as the services were performed since the Company did not bear the risk of completion of the well. The Company received lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another were recognized at the time mobilization services were performed. Revenues and expenses related to drilling and services are included in other revenue and expense in the accompanying consolidated statements of operations for the years ended December 31, 2015 and 2014.

In general, natural gas purchased and sold by the midstream business was priced at a published daily or monthly index price. Sales to wholesale customers typically incorporated a premium for managing their transmission and balancing requirements. Midstream services revenues were recognized upon delivery of natural gas to customers and/or when services were rendered, pricing was determined and collectability was reasonably assured. Revenues from third-party midstream services were presented on a gross basis, since the Company acted as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold. Revenues and expenses related to midstream and marketing are included in other revenue and expense in the accompanying consolidated statements of operations for the years ended December 31, 2015 and 2014.

F-21

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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 are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.

Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the Successor Company consist of unvested restricted stock awards 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.

Under the if-converted method, the Successor Company assumes the conversion of the New Convertible Notes to common stock and determines if it is more dilutive than including the expense associated with the New Convertible Notes in the computation of income available to common stockholders. Under the if-converted method, the Predecessor Company assumed the conversion of the preferred stock or Convertible Senior Unsecured Notes to common stock 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 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 19 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. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 14 for discussion of the Company’s commitments and contingencies.

Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its commodity derivative counterparties and considers its counterparties’ 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 its exposure to any individual counterparty.

A default by the Company under its New First Lien Exit Facility constitutes a default under its commodity derivative contracts with counterparties that are lenders under the New First Lien Exit 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 First Lien Exit Facility can be offset against amounts owed, if any, to such counterparty under the Company’s First Lien Exit facility.

F-22

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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 consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major 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 the Company’s ability to sell the oil, natural gas and NGLs it produces.

The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):

	Sales		% of Revenue
Period from October 2, 2016 through December 31, 2016 - Successor
Targa Pipeline Mid-Continent West OK LLC	$	35,845	36.4	%
Plains Marketing, L.P.	$	32,022	32.5	%
Period from January 1, 2016 through October 1, 2016 - Predecessor
Plains Marketing, L.P.	$	110,370	37.6	%
Targa Pipeline Mid-Continent West OK LLC	$	108,238	36.8	%
December 31, 2015 - Predecessor
Plains Marketing, L.P.	$	318,018	41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649	30.1	%
December 31, 2014 - Predecessor
Plains Marketing, L.P.	$	597,117	38.3	%
Targa Pipeline Mid-Continent West OK LLC	$	333,027	21.4	%

Recent Accounting Pronouncements. The Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2015-02, “Amendments to the Consolidation Analysis,” which simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a VIE. The requirements of the guidance were effective for annual reporting periods beginning January 1, 2016 for the Company, including interim periods within that reporting period, with early adoption permitted. The Company adopted this guidance on January 1, 2016, which resulted in the determination that the Royalty Trusts no longer qualify as VIEs. As a result, the Successor and Predecessor Companies proportionately consolidated the activities of the Royalty Trusts in 2016. Under the proportionate consolidation method, the Company accounts for only its share of each Royalty Trust’s asset, liabilities, revenues and expenses within the appropriate classifications in the accompanying consolidated financial statements. The Company adopted the provisions of ASU 2015-02 on a modified retrospective approach by recording a cumulative-effect adjustment as of January 1, 2016 that resulted in decreases of approximately $243.4 million to total assets and approximately $510.2 million to noncontrolling interest and increases of approximately $9.7 million to accounts payable and approximately $257.1 million to retained earnings. These adjustments had no impact on prior period balances.

The FASB issued ASU 2015-03, "Interest-Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs," which requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. The guidance was adopted on January 1, 2016, and resulted in a decrease of approximately $69.1 million to other assets and current maturities of long-term debt in the accompanying consolidated balance sheet for the year ended December 31, 2015, with no impact to the accompanying consolidated statements of operations. See Note 11 for treatment and classification of unamortized debt issuance costs subsequent to filing the Chapter 11 petitions. In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements,” which excludes line-of-credit debt issuance costs from the scope of ASU 2015-03. The guidance was adopted on January 1, 2016 in conjunction with the adoption of ASU 2015-03. The Company made

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

an accounting policy election to present line-of-credit arrangement debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement. The adoption of this ASU resulted in no impact to the consolidated financial statements.

The FASB issued ASU 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The Company adopted the provisions of this ASU for the year ended December 31, 2016 on a prospective basis. The adoption of this ASU had no impact to the Company’s disclosures included in this report.

The FASB issued ASU 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments” which eliminates diversity in practice in assessing embedded contingent call (put) options in debt instruments. The ASU requires adoption by application of a modified retrospective approach to existing and future debt instruments. The ASU is effective for the Company beginning January 1, 2017, with early adoption permitted. The Company early adopted the provisions of this ASU on the Emergence Date. The adoption of this ASU resulted in no impact to the consolidated financial statements and related disclosures.

The FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Share-Based Payment Accounting” which was part of the FASB simplification initiative and involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance requires adoption by various application methods, effective for the Company beginning January 1, 2017. The Company early adopted all provisions of this ASU on the Emergence Date. Upon adoption, the Company made an accounting policy election to account for forfeitures as they occur. The adoption of this ASU resulted in no impact to the consolidated financial statements and related disclosures.

The FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” to require inclusion of amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. This ASU is effective for the Company beginning January 1, 2018. The Company early adopted the provisions of this ASU on December 31, 2016, using a retrospective transition method for each period presented. As a result of the adoption, the Company included $52.8 million of restricted cash in the beginning of period and end of period total amounts shown on the Successor statement of cash flows for October 2, 2016 and December 31, 2016, respectively. There was no impact to the Predecessor statement of cash flows.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which provides guidance concerning the recognition and measurement of revenue 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 defers the effective date of ASU 2014-09 to January 1, 2018 for the Company, with early adoption permitted in 2017. The ASU must be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes 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 does not plan to early adopt and is currently evaluating the effect that the updated standard will have on its consolidated financial statements and related disclosures.

The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for the Company on January 1, 2019. Early adoption is permitted. The Company does not plan to early adopt and is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

The FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” with the objective of reducing the existing diversity in practice of classification on certain cash receipts and payments in the statement of cash flows. The guidance requires adoption by application of a retrospective method to each period presented. The amendments are effective for the Company on January 1, 2018, with early adoption permitted. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory” which removes 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 are effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU should be applied 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 does not plan to early adopt and is currently evaluating the effect that the guidance will have on its consolidated financial statements.

The FASB Issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides more consistency in applying the guidance, reduces the costs of application, and makes the definition of a business more operable. The ASU is effective for the Company on January 1, 2018 and amendments should be applied prospectively on and after January 1, 2018. Due to the prospective nature of the ASU, the Company cannot evaluate the impact to its consolidated financial statements until after adoption, and no disclosures are required upon transition.

4. Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items	$	—		$	(55,606	)	$	—		$	—
Cash paid for interest, net of amounts capitalized	$	(1,183	)	$	(104,609	)	$	(296,386	)	$	(235,793	)
Cash (paid) received for income taxes	$	—		$	(28	)	$	(88	)	$	1,928
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	$	10,630		$	25,045		$	177,586		$	(55,557	)
Equity issued for debt	$	(13,001	)	$	(4,409	)	$	(63,299	)	$	—
Preferred stock dividends paid in common stock	$	—		$	—		$	(16,188	)	$	—
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$	—		$	—		$	(50,310	)	$	—

F-25

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

5. Acquisitions and Divestitures

Predecessor Acquisitions and Divestitures

2016 Divestiture

Divestiture of West Texas Overthrust Properties and Release from Treating Agreement. On January 21, 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 West Texas Overthrust (“WTO”) to Occidental Petroleum Corporation (“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.

2015 Acquisitions

Acquisition of Piñon Gathering Company, LLC. In October 2015, the Company acquired all of the assets of and terminated a gathering agreement with PGC for $48.0 million in cash and $78.0 million principal amount of newly issued PGC Senior Secured Notes. PGC owned approximately 370 miles of gathering lines supporting the natural gas production from the Company's Piñon field in the WTO. The transaction resulted in the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. The fair value of the consideration paid by the Company, including discount attributable to the PGC Senior Secured Notes, was approximately $98.3 million and was allocated on a fair value basis between the assets acquired (approximately $47.3 million) and a loss on the termination of the gathering contract (approximately $51.0 million).

Acquisition of Rockies Properties. In December 2015, the Company acquired approximately 135,000 net acres in the North Park Basin in the Rockies, in Jackson County, Colorado. The Company paid approximately $191.1 million in cash, including post-closing adjustments, and received $3.1 million from the seller for overriding royalty interests. Also included in the acquisition were working interests in 16 wells previously drilled on the acreage.

2014 Divestiture

Sale of Gulf of Mexico and Gulf Coast Properties. On February 25, 2014, the Company sold subsidiaries that owned the Company’s Gulf of Mexico and Gulf Coast oil and natural gas properties (collectively, the “Gulf Properties”) for approximately $702.6 million, net of working capital adjustments and post-closing adjustments, and the buyer’s assumption of approximately $366.0 million of related asset retirement obligations to Fieldwood Energy, LLC (“Fieldwood”). This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss on the sale. See Note 20 for discussion of Fieldwood’s related party affiliation with the Company.

In accordance with the terms of the sale, the Company agreed to guarantee on behalf of Fieldwood certain plugging and abandonment obligations associated with the Gulf Properties for a period of up to one year from the date of closing. The Company recorded a liability equal to the fair value of these guarantees, or $9.4 million, at the time the transaction closed. See Note 6 for additional discussion of the determination of the guarantee’s fair value. The guarantee did not limit the Company’s potential future payment obligations; however, Fieldwood agreed to indemnify the Company for any costs it incurred as a result of the guarantee and to use its best efforts to pay any amounts sought from the Company by the Bureau of Ocean Energy Management (“BOEM”) that arose prior to the expiration of the guarantee. The Company did not incur any costs as a result of this guarantee and was released from the obligation during the third quarter of 2015. Additionally, Fieldwood maintained, for a period of up to one year from the closing date, restricted deposits held in escrow for plugging and abandonment obligations associated with the Gulf Properties. In the first quarter of 2015, the Company received its share of such deposits, net of any amounts payable to Fieldwood, or $12.0 million, in accordance with the terms of the sale.

The company recorded revenues and expenses of $90.9 million and $63.7 million, respectively, through the date of the sale, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties which are included in the Predecessor Company’s accompanying consolidated statement of operations for the year ended December 31, 2014.

F-26

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

6. 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 following levels of the fair value hierarchy:

Level 1	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3	Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in each level of the hierarchy as of December 31, 2016 and 2015, as described below.

Level 1 Fair Value Measurements

Investments. The fair value of investments, consisting of assets attributable to the Company’s non-qualified deferred compensation plan, is based on quoted market prices. Investments are included in other current assets and other assets in the accompanying consolidated balance sheets.

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.

Mandatory Prepayment Feature - PGC Senior Secured Notes. In conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015, the Company issued the PGC Senior Secured Notes as discussed in Note 5. The PGC Senior Secured Notes were issued at a substantial discount, as discussed in Note 11 and Note 12, which resulted in the treatment of the mandatory prepayment feature as an embedded derivative that met the criteria to be bifurcated from its host contract and accounted for separately from the PGC Senior Secured Notes. Prior to Chapter 11 filings, the mandatory prepayment feature was recorded at fair value each reporting period based upon values determined through the use of discounted cash flow models of the PGC Senior Secured Notes both (i) with the mandatory prepayment feature and (ii) excluding the mandatory prepayment feature. Subsequent to the Chapter 11 filings in May 2016, the value of the mandatory repayment feature of $2.5 million was written off and is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period.

Level 3 Fair Value Measurements

Commodity Derivative Contracts. The Company had natural gas basis swaps outstanding on the Emergence Date and at December 31, 2015 and 2014. The fair value of the natural gas basis swaps was based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness through the use of a discounted cash flow model using non-exchange traded regional pricing information. Additionally, the Company applied a weighted average credit default risk rating factor for its counterparties or gave effect to its credit risk, as applicable, in determining the fair value of the commodity derivative contracts. The significant unobservable input that was used in the fair value measurement of the Company’s natural gas basis swaps was the estimate of future natural gas basis differentials. The fair value of the natural gas basis swaps and

F-27

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

any purchases, gains/losses and settlements were insignificant for the Predecessor 2016 Period and for the years ended December 31, 2015 and 2014. No natural gas basis swaps were outstanding at December 31 2016.

Debt Holder Conversion Feature. The Predecessor Company’s Convertible Senior Unsecured Notes each contained a conversion option whereby, prior to Chapter 11 filings, the Convertible Senior Unsecured Notes holders had the option to convert the notes into shares of Company common stock. These conversion features were identified as embedded derivatives that met the criteria to be bifurcated from their host contracts and accounted for separately from the Convertible Senior Unsecured Notes. Subsequent to the Chapter 11 filings, the value of the debt holder conversion feature of $7.3 million was written off and is included in reorganization items in the accompanying statement of operations for the Predecessor 2016 Period.

The fair values of the holder conversion features were determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) recovery rate, (iv) hazard rate and (v) expected volatility. The significant unobservable input used in the fair value measurement of the conversion features was the hazard rate, an estimate of default probability. The significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion features atDecember 31, 2015are included in the table below.

Unobservable Input	Range					Weighted Average		Fair Value
								(In thousands)
Debt conversion feature hazard rate	114.0	%	–	135.2	%	119.2	%	$	29,355

See further discussion of the Convertible Senior Unsecured Notes at Note 11.

Guarantee. The Company guaranteed on behalf of Fieldwood certain plugging and abandonment obligations associated with the sale of its Gulf Properties from the date of closing until the Company was released from the guarantee in the third quarter of 2015. The significant unobservable input used in the fair value measurement of the guarantees was the estimate of future payments for plugging and abandonment of approximately $372.0 million, which was developed based upon third-party quotes and then-current actual costs. While in effect, the fair value of the guarantee was determined quarterly with changes in fair value recorded as an adjustment to the full cost pool. See Note 5 for discussion of the sale of the Gulf Properties. The fair value of the guarantee and any issuances and settlements were insignificant for the year ended December 31, 2014.

F-28

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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, 2016 - Successor

	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Investments	$	7,541	$	—	$	—	$	—	$	7,541
	$	7,541	$	—	$	—	$	—	$	7,541
Liabilities
Commodity derivative contracts	$	—	$	29,714	$	—	$	—	$	29,714
	$	—	$	29,714	$	—	$	—	$	29,714

December 31, 2015 - Predecessor

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	85,524	$	—	$	(1,175	)	$	84,349
Investments	10,106		—		—		—			10,106
	$	10,106	$	85,524	$	—	$	(1,175	)	$	94,455
Liabilities
Commodity derivative contracts	$	—	$	—	$	1,748	$	(1,175	)	$	573
Debt holder conversion feature	—		—		29,355		—			29,355
Mandatory prepayment feature - PGC Senior Secured Notes	—		2,941		—		—			2,941
	$	—	$	2,941	$	31,103	$	(1,175	)	$	32,869

____________________

(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.    

Level 3 - Debt Holder Conversion Feature. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for debt holder conversion features (in thousands):

	Predecessor
	Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015
Beginning balance	$	29,355		$	—
Issuances	—			31,200
(Loss) gain on derivative holder conversion feature	(880		)	10,198
Conversions	(21,194		)	(12,043		)
Write off of derivative holder conversion feature to reorganization items	(7,281		)	—
Ending level 3 debt holder conversion feature balance	$	—		$	29,355

Prior to commencement of the Chapter 11 Proceedings, the fair values of the conversion features were determined quarterly with changes in fair value recorded as interest expense.

Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the years ended December 31, 2016, 2015 and 2014, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

F-29

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Fair Value of Financial Instruments - Long-Term Debt

The Successor Company measures the fair value of its New Convertible Notes using pricing that was readily available in the public market at December 31, 2016. The Successor Company measures the fair value of its New Building Note using a discounted cash flow analysis. The Predecessor Company also measured the fair value of its Senior Secured Notes and the Unsecured Notes using pricing that was readily available in the public market. The Company classifies these inputs as Level 2 in the fair value hierarchy. The estimated fair values and carrying values of the Company’s notes are as follows (in thousands):

	Successor				Predecessor
	December 31, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
New Convertible Notes	$	334,800	$	268,780	$	—	$	—
New Building Note	$	40,608	$	36,528	$	—	$	—
8.75% Senior Secured Notes due 2020	$	—	$	—	$	403,098	$	1,265,814
Senior Unsecured Notes
8.75% Senior Notes due 2020	$	—	$	—	$	39,740	$	389,232
7.5% Senior Notes due 2021	$	—	$	—	$	79,812	$	751,087
8.125% Senior Notes due 2022	$	—	$	—	$	57,749	$	518,693
7.5% Senior Notes due 2023	$	—	$	—	$	58,799	534,869
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022	$	—	$	—	$	44,199	$	78,290
7.5% Convertible Senior Notes due 2023	$	—	$	—	$	15,125	$	24,393

See Note 1 for additional information regarding the bankruptcy proceedings and Note 11 for discussion of the Company’s long-term debt.

Fair Value of Non-Financial Assets and Liabilities

See Note 2 for additional information regarding fair value adjustments for non-financial assets and liabilities resulting from the application of fresh start accounting and Note 9 for discussion of the Company’s impairment valuations.

F-30

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

7. Accounts Receivable

A summary of accounts receivable is as follows (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
Oil, natural gas and NGL sales	$	42,631		$	61,140
Joint interest billing	17,338			60,403
Oil and natural gas services	736			2,417
Other	14,272			8,274
Total accounts receivable	74,977			132,234
Less: allowance for doubtful accounts	(880		)	(4,847		)
Total accounts receivable, net	$	74,097		$	127,387

The following table presents the balance and activity in the allowance for doubtful accounts for the Successor 2016 Period, the Predecessor 2016 Period and years ended December 31, 2015 and 2014 (in thousands):

	Successor					Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning balance	$	—	$	4,847		$	7,083		$	11,061
Additions charged to costs and expenses(1)	880		16,695			1,320			818
Deductions(2)	—		(751		)	(3,556		)	(4,796		)
Impact of fresh start accounting	—		(20,791		)	—			—
Ending balance	$	880	$	—		$	4,847		$	7,083

____________________

(1) The Predecessor 2016 Period includes an addition for a joint interest account receivable after a determination that future collection was doubtful.

(2) Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2015 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement and deductions in 2014 are related to the sale of the Gulf Properties.

F-31

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

8. Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
Oil and natural gas properties
Proved(1)	$	840,201		$	12,529,681
Unproved	74,937			363,149
Total oil and natural gas properties	915,138			12,892,830
Less accumulated depreciation, depletion and impairment	(353,030		)	(11,149,888		)
Net oil and natural gas properties capitalized costs	562,108			1,742,942
Land	5,100			14,260
Non-oil and natural gas equipment(2)	166,010			373,687
Buildings and structures(3)	88,603			227,673
Total	259,713			615,620
Less accumulated depreciation and amortization	(3,889		)	(123,860		)
Other property, plant and equipment, net	255,824			491,760
Total property, plant and equipment, net	$	817,932		$	2,234,702

____________________

(1) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $48.9 million at December 31, 2015.

(2) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $4.3 million at December 31, 2015.

(3) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $20.4 million at December 31, 2015.

In connection with the application of fresh start accounting as of October 1, 2016, the Company recorded fair value adjustments disclosed in Note 2. Accumulated depreciation, depletion and impairment was therefore eliminated as of that date.

Accumulated depreciation, depletion and impairment for the Predecessor Company oil and natural gas properties includes cumulative full cost ceiling limitation impairment of $8.2 billion at December 31, 2015.

During the Successor 2016 Period the Successor Company reduced the net carrying value of its oil and natural gas properties by $319.1 million and for the Predecessor 2016 Period, the Predecessor Company reduced the net carrying value of its oil and natural gas properties by $657.4 million, as a result of quarterly full cost ceiling analyses in the respective periods. The Company reduced the net carrying value of its oil and natural gas properties by $4.5 billion and $164.8 million during the years ended December 31, 2015 and 2014, respectively. See Note 9 for discussion of impairment of other property, plant and equipment.

The average rates used for depreciation and depletion of oil and natural gas properties were $7.82 per Boe for the Successor 2016 Period, $5.76 per Boe for the Predecessor 2016 Period, $10.67 per Boe in 2015 and $15.00 per Boe in 2014.

During the second and fourth quarters of 2015, the Company classified drilling and oilfield services assets having net book values of approximately $20.0 million and $16.0 million, respectively, as held for sale as a result of the Company’s decisions to discontinue substantially all drilling and oilfield services operations first in the Permian region and then companywide. A portion of these assets were disposed of during the third quarter of 2015, resulting in a loss recorded in other operating expenses in the accompanying consolidated statement of operations of $3.5 million for the year ended December 31, 2015.

The remaining $16.0 million in assets held for sale at December 31, 2015 were sold during 2016, resulting in insignificant (loss) gain on sale of assets recorded for the Successor 2016 period and the Predecessor 2016 period. No significant assets were classified as held for sale at December 31, 2016.

F-32

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Drilling Carry Commitments

During the year ended December 31, 2014, the Company was party to an agreement with Repsol E&P USA, Inc. (“Repsol”), which contained a carry commitment to fund a portion of its future drilling, completing and equipping costs within areas of mutual interest. The Company recorded approximately $205.6 million for Repsol’s carry during the year ended December 31, 2014, which reduced the Company’s capital expenditures for the respective periods. Repsol fully funded its carry commitment in the third quarter of 2014.

Under the terms of an amended agreement with Repsol, the Company committed to drill 484 net wells in an area of mutual interest and to carry Repsol’s future drilling and completion costs in the amount of $1.0 million for each committed well that it did not drill, up to a maximum of $75.0 million in carry costs.  As of May 31, 2015, the Company had drilled 453 net wells under this arrangement and as a result, the Company was obligated under the agreement to carry a portion of Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled after that time in the area of mutual interest. The Company incurred approximately $6.2 million and $16.1 million in costs toward this obligation for the Predecessor 2016 Period and the year ended December 31, 2015, respectively. Effective June 6, 2016, the Bankruptcy Court issued orders allowing the Company to reject certain long-term contracts, including this drilling carry commitment. Repsol filed a bankruptcy claim for this commitment, which was settled by the Company for approximately $1.2 million.

Costs Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2016 (in thousands):

			Year Cost Incurred
	Total		2016		2015		2014		2013 and Prior
Property acquisition	$	71,171	$	7,390	$	18,959	$	34,770	$	10,052
Exploration(1)	20,459		2,123		10,578		4,678		3,080
Total costs incurred	$	91,630	$	9,513	$	29,537	$	39,448	$	13,132

____________________

(1) Includes $16.7 million of pipe inventory costs incurred ($2.1 million in 2016, $9.6 million in 2015 and $5.0 million in 2014 and prior years).

The Company expects to complete the majority of the evaluation activities within 10 years from the applicable date of acquisition, contingent on the Company’s capital expenditures and drilling program. In addition, the Company’s internal engineers evaluate all properties on at least an annual basis.

F-33

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

9. Impairment

As deemed necessary based on events in 2016, 2015 and 2014, the Company analyzed various property, plant and equipment for impairment by comparing the carrying values of these 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 3.

Impairment consists of the following (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Full cost pool ceiling limitation(1)(2)(3)	$	319,087	$	657,392	$	4,473,787	$	164,779
Drilling assets(4)	—		3,511		37,646		27,428
Electrical transmission assets(5)	—		55,600		—		—
Midstream assets(6)	—		1,691		7,148		561
Other(7)	—		—		16,108		—
	$	319,087	$	718,194	$	4,534,689	$	192,768

____________________

(1) Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting. 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 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 impairments recorded in 2015 and the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes.

(3) Impairment in 2014 resulted from the divestiture of the Gulf Properties.

(4) Impairment recorded in the Predecessor 2016 Period and the year ended December 31, 2015, resulted from discontinued drilling operations in its Permian region which resulted in an impairment on certain drilling assets after determining their future use was limited. During 2014, the Company recorded a $24.3 million impairment on its drilling and oilfield services assets in the Permian region as a result of fulfilling its drilling obligation with the Permian Trust in 2014 and the downward trend in oil prices that began in the second half of 2014.

(5) Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage.

(6) Impairment in the Predecessor 2016 Period and the years ended December 31, 2015 and 2014 resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a carbon dioxide (“CO₂”) compressor station after determining that their future use was limited.

(7) Impairment recorded on other assets in 2015, includes a $15.4 million impairment on property located in downtown Oklahoma City, Oklahoma to adjust the carrying value of the property to the agreed upon sales price for which it was later sold in 2016.

F-34

10. Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):

	Successor		Predecessor
	December 31,		December 31,
	2016		2015
Accounts payable and other accrued expenses	$	65,408	$	231,697
Accrued interest	648		73,320
Production payable	16,011		55,260
Payroll and benefits	33,606		42,728
Convertible perpetual preferred stock dividends	—		21,572
Drilling advances	844		2,295
Related party	—		1,545
Total accounts payable and accrued expenses	$	116,517	$	428,417

11. Long-Term Debt

Long-term debt consists of the following (in thousands):

	Successor		Predecessor
	December 31,		December 31,
	2016		2015
New First Lien Exit Facility	$	—	$	—
New Convertible Notes	268,780		—
New Building Note	36,528		—
Senior credit facility	—		—
8.75% Senior Secured Notes due 2020	—		1,265,814
Senior Unsecured Notes
8.75% Senior Notes due 2020	—		389,232
7.5% Senior Notes due 2021	—		751,087
8.125% Senior Notes due 2022	—		518,693
7.5% Senior Notes due 2023	—		534,869
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022	—		78,290
7.5% Convertible Senior Notes due 2023	—		24,393
Total debt	305,308		3,562,378
Less: current maturities of long-term debt	—		—
Long-term debt	$	305,308	$	3,562,378

On the Emergence Date, the balance outstanding under the senior credit facility of $449.2 million, par value of the Senior Secured Notes of $1.3 billion, par value of the Senior Unsecured Notes of $2.2 billion and par value of the Convertible Senior Unsecured Notes of $87.6 million were canceled upon emergence from bankruptcy and the Company entered into the New First Lien Exit Facility, issued New Convertible Notes and entered into the New Building Note as discussed further below. See Note 1 for additional information regarding the bankruptcy proceedings.

See Note 6 for the fair values and carrying values of the long-term debt outstanding at December 31, 2016 and 2015, respectively, and Note 2 for fresh start values calculated as of the Emergence Date. As of December 31, 2015, there were no amounts outstanding under the senior credit facility, and the carrying values of the senior notes were net of unamortized discounts, premiums and deferred costs of $342.6 million, and included the fair value of debt derivatives of $32.3 million. A non-cash charge to write off all of the related unamortized debt issuance costs and associated discounts and premiums of approximately $158.6 million and the fair value of associated debt derivatives of $9.8 million as of May 16, 2016, is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period, as discussed in Note 1 and Note 2.

F-35

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Successor Company Indebtedness

New First Lien Exit Facility. As discussed in Note 1, on the Emergence Date, the Company entered into the New First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender.

The initial borrowing base under the New First Lien Exit Facility is $425.0 million. There are no scheduled borrowing base redeterminations until October 2018, followed by scheduled semiannual borrowing base redeterminations thereafter. The New First Lien Exit Facility matures on February 4, 2020. The outstanding borrowings under the New First Lien Exit Facility bear interest at a rate equal to, at the option of the Company, either (a) a base rate plus an applicable rate of 3.75% per annum or (b) LIBOR plus 4.75% per annum, subject to a 1.00% LIBOR floor. Interest on base rate borrowings 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 New First Lien Exit Facility. The Company has the right to prepay loans under the New First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans.

Furthermore, the New First Lien Exit Facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of the proved developed producing reserves and 95% of the PV-9 valuation of all proved reserves included in the most recently delivered reserve report of the Company, (ii) a first-priority perfected pledge of capital stock of each credit party and their respective wholly owned subsidiaries and (iii) a first-priority security interest in the cash, cash equivalents, deposit, securities and other similar accounts, and a first-priority perfected security interest in substantially all 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 New First Lien Exit Facility requires the Company to, (a) commencing with the first full fiscal quarter ending after the Protected Period, maintain a minimum proved developing producing reserves asset coverage ratio, measured as of the last day of each fiscal quarter, of 1.75 to 1.00 and (b) commencing with the first full fiscal quarter ending after the occurrence of the end of the Protected Period, maintain (i) a maximum consolidated total net leverage ratio, measured as of the last day of each fiscal quarter, (A) on or prior to December 31, 2018, of no greater than 3.50 to 1.00, and (B) any fiscal quarter ending on or after March 31, 2019, of no greater than 3.00 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the last day of each fiscal quarter, of no less than 2.00 to 1.00. Such financial covenants are subject to customary cure rights.

The New First Lien Exit Facility contains customary affirmative and negative covenants, including compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants.

The Company had no amounts outstanding under the New First Lien Exit Facility at December 31, 2016 and $8.6 million in outstanding letters of credit, which reduce availability under the New First Lien Exit Facility on a dollar-for-dollar basis.

The Company subsequently refinanced the New First Lien Exit Facility in February 2017. See Note 21 for additional discussion.

New 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 New Convertible Notes, which do not bear regular interest and will mature and mandatorily convert into New Common Stock on October 4, 2020, unless repurchased, redeemed or converted prior to that date. The New Convertible Notes were recorded at fair value of $445.7 million upon implementation of fresh start accounting. As the associated premium of $163.9 million was deemed significant to the principal amount of the New Convertible Notes, it was recorded in additional paid in capital in the consolidated balance sheet at December 31, 2016. Upon the occurrence of certain events, including any acceleration, repayment or prepayment of the New Convertible Notes (including any optional redemption), the Company will be required to pay a make-whole amount of $0.783478 for each $1.00 in principal amount of New Convertible Notes repaid or prepaid in accordance with the provisions of the associated indenture.

The New Convertible Notes are initially convertible at a conversion rate of 0.05330841 shares of New Common Stock per $1.00 principal amount of New Convertible Notes, which represents, in the aggregate, approximately 15.0 million shares of the New Common Stock. The conversion rate for the New Convertible Notes is subject to customary anti-dilution adjustments. In addition, upon the occurrence of certain events, including any acceleration, repayment or prepayment of the New Convertible Notes (including any optional redemption), the conversion rate will be automatically adjusted such that the New Convertible Notes convert into the same percentage of New Common Stock before and after such event.

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The New Convertible Notes are convertible at the option of the holders at any time up to, and including, the business day immediately preceding the maturity date. In addition, the Company is required to convert all outstanding New Convertible Notes upon the earliest to occur of the following: (i) any bona fide arm’s length issuance by the Company of New Common Stock to third parties for cash with (a) a total issuance size that is greater than or equal to $100.0 million and (b) a per-share price greater than or equal to $34.16; (ii) 30 days’ written notice to the Company to convert the New Convertible Notes from holders of at least a majority in aggregate principal amount of the New Convertible Notes then outstanding; (iii) the average of the last reported sale prices of the New Common Stock over a 30 consecutive trading day period is 50% greater than $34.16; (iv) any bona fide refinancing of the New First Lien Exit Facility after a determination by the post-emergence board of directors in good faith that: (a) such refinancing provides for terms that are materially more favorable to the Company and (b) the causing of a conversion is not the primary purpose of such refinancing; (v) any change of control transaction; or (vi) the maturity date. Upon conversion, the Company will deliver shares of New Common Stock equal to the conversion rate, together with a cash payment in lieu of delivering any fractional share of New Common Stock issuable upon conversion, based on the last reported sale price of the New Common Stock on the relevant conversion date. During the Successor 2016 Period, holders of approximately $13.0 million in aggregate principal amount of the New Convertible Notes exercised conversion options applicable to those notes, resulting in the issuance of approximately 0.7 million shares of New Common Stock.

The Company may redeem for cash all or part of the New Convertible Notes at any time prior to the maturity date, at a redemption price equal to 100% of the principal amount of such New Convertible Notes to be redeemed, as increased by the make-whole amount. With respect to any New Convertible Notes selected for redemption that are converted following a redemption notice, the conversion rate will be automatically adjusted such that the New Convertible Notes convert into the same percentage of New Common Stock before and after such redemption notice.

The Company’s obligations pursuant to the New Convertible Notes are fully and unconditionally guaranteed, jointly and severally, by each of the Guarantors of the New First Lien Exit Facility. Following the occurrence of certain events, the Company would be required to secure $100.0 million of the New Convertible Notes, which amount may be increased to the full outstanding principal amount of the New Convertible Notes, including any applicable make-whole amount, in accordance with the provisions of the New Convertible Notes Indenture (the “Springing Lien”). The Springing Lien will be a second priority lien on the same collateral securing the New First Lien Exit Facility.    

The remaining outstanding New Convertible Notes were converted into shares of New Common Stock as a result of the Company’s entry into the refinanced credit facility on February 10, 2017, as discussed in Note 21.

New Building Note. As discussed in Note 1, on the Emergence Date, the Company entered into the New Building Note, which has a principal amount of $35.0 million and is secured by first priority mortgage on the Company’s headquarters facility and certain other non-oil and gas real property. The New Building Note was recorded at fair value of $36.6 million upon implementation of fresh start accounting. Interest is payable on the New Building Note at 6% per annum for the first year following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. The effective interest rate was 10.9% for the New Building Note at December 31, 2016. Interest is payable in kind from the Emergence Date through the earlier of September 30, 2020, 46 months from the Emergence Date or 90 days after the refinancing or repayment of the New First Lien Exit Facility and thereafter in cash. The New Building Note matures on October 4, 2021. On the Emergence Date, pursuant to the Plan, certain holders of the Unsecured Senior Notes purchased the New Building Note for $26.8 million in cash, net of certain fees and expenses.

Predecessor Company Indebtedness

Senior Credit Facility. The terms of the senior credit facility contained certain financial covenants, including maintenance of agreed upon levels for the (a) ratio of total secured debt under the senior credit facility to earnings before interest, taxes, depreciation and amortization (“EBITDA”), which could not exceed 2.00:1.00 at each quarter end and (b) ratio of current assets to current liabilities, which was required to be at least 1.0:1.0 at each quarter end. For the purpose of the current ratio calculation, any amounts available to be drawn under the senior credit facility were included in current assets and unrealized assets and liabilities that resulted from mark-to-market adjustments on the Company’s commodity derivative contracts were disregarded. The senior credit facility matured by its terms on the earlier of March 2, 2020 and 91 days prior to the earliest date of any maturity under or mandatory offer to repurchase the Company’s then outstanding notes.

The senior credit facility also contained various covenants that limited the ability of the Company and certain of its subsidiaries to: grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. The terms of the senior credit facility allowed the Company to redeem or purchase outstanding Senior

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Notes to Consolidated Financial Statements - (Continued)

Unsecured Notes for up to $275.0 million in cash subject to certain limitations. Additionally, the senior credit facility limited the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions.

The obligations under the senior credit facility were guaranteed by certain Company subsidiaries and were required to be secured by first priority liens on all shares of capital stock of certain of the Company’s material present and future subsidiaries, all of the Company’s intercompany debt, and certain of the Company’s other assets, including proved oil, natural gas and NGL reserves representing at least 80.0% of the discounted present value (as defined in the senior credit facility) of proved oil, natural gas and NGL reserves of the Company.

At the Company’s election, interest under the senior credit facility, was determined by reference to (a) LIBOR plus an applicable margin between 1.750% and 2.750% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Royal Bank of Canada under the senior credit facility or (iii) the one-month Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 0.750% and 1.750% per annum. Interest was payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan was six months or longer, interest was paid at the end of each three-month period. Quarterly, the Company paid commitment fees assessed at annual rates of 0.5% on any available portion of the senior credit facility.

On March 11, 2016, the administrative agent notified the Company that the lenders had elected to reduce the borrowing base to $340.0 million from $500.0 million pursuant to a special redetermination. On April 20, 2016, the Company submitted for consideration by its lenders additional properties to serve as collateral under the senior credit facility to support a borrowing base of $500.0 million. On May 11, 2016, in exchange for waivers from the requisite percentage of lenders with respect to certain specified defaults and events of defaults under the senior credit facility, the Company permanently repaid $40.0 million of borrowings to the lenders, which payment correspondingly reduced the lenders’ commitments.

Senior Secured Notes. The Company issued $1.25 billion of 8.75% Senior Secured Notes due 2020 in June 2015. Net proceeds from the issuance were approximately $1.21 billion after deducting offering expenses, a portion of which was used to repay amounts outstanding at that time under the Company’s senior credit facility.

Additionally, the Company issued $78.0 million par value of the PGC Senior Secured Notes in conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015. Because the PGC Senior Secured Notes were issued as partial consideration for the acquisition and termination, these notes were recorded at fair value of approximately $50.3 million, which included mandatory prepayment feature liabilities and a discount. Fair value at issuance was determined based upon the then-current market value of the Senior Secured Notes. The unamortized portions of the discount and the carrying value of the mandatory prepayment feature as of the date of the Chapter 11 filings, May 16, 2016, were written off to reorganization items on the accompanying consolidated statement of operations for the Predecessor 2016 Period as discussed in Note 1.

The Company accrued interest on its Senior Secured Notes at a fixed rate of 8.75% prior to the Chapter 11 filings, with no interest accrued subsequent to the filings. The Senior Secured Notes were by their terms redeemable, in whole or in part, prior to their maturity at specified redemption prices and were jointly and severally guaranteed unconditionally, in full, on a second-priority secured basis by certain of the Company’s wholly owned subsidiaries.

The Senior Secured Notes were secured by second-priority liens on all of the Company’s assets that secured the senior credit facility on a first-priority basis; provided, however, the security interest in those assets that secured the Senior Secured Notes and the guarantees were contractually subordinated to liens thereon that secured the credit facility and certain other permitted indebtedness. Consequently, the Senior Secured Notes and the guarantees were effectively subordinated to the credit facility and such other indebtedness to the extent of the value of such assets.

Pursuant to the indenture, the Senior Secured Notes by their terms matured on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeded $100.0 million, the Senior Secured Notes would mature on October 16, 2019. See further discussion of the mandatory prepayment feature at Note 6 and Note 12, which with respect to the PGC Senior Secured Notes was an embedded derivative that was accounted for separately from these notes, and was written off to reorganization items on the accompanying consolidated statement of operations for the Predecessor 2016 Period as discussed in Note 1.

The indenture governing the Senior Secured Notes contained covenants that restricted the Company’s ability to pay dividends, incur indebtedness, create liens, enter into consolidations or mergers, purchase or redeem stock or subordinated or unsecured indebtedness, dispose of or transfer certain assets, transact with related parties, make investments and refinance certain indebtedness, among other actions. These indentures were canceled upon the Company’s emergence from Chapter 11. See

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Notes to Consolidated Financial Statements - (Continued)

Note 1 for additional details about the Company’s Bankruptcy Petitions and the Chapter 11 proceedings.

Senior Unsecured Notes. The Company accrued interest on its Senior Unsecured Notes at a fixed rate through the date of the Chapter 11 filings, with no interest accrued subsequent to the filings. Certain of the Senior Unsecured Notes were issued at a discount or a premium. Prior to the Chapter 11 filings, the discount or premium was amortized to interest expense over the term of the respective series of Senior Unsecured Notes. The unamortized portions of the discount or premium as of the date of the Chapter 11 filings, May 16, 2016, were written off to reorganization items on the accompanying consolidated statement of operations for the Predecessor 2016 Period as discussed in Note 1.

Each of the indentures governing the Company’s Senior Unsecured Notes contained covenants that restricted the Company’s ability to pay dividends, incur indebtedness, make investments, sell certain assets, purchase certain assets, transact with related parties and enter into consolidations or mergers. These indentures were canceled upon the Company’s emergence from Chapter 11.

Convertible Senior Unsecured Notes. The Convertible Senior Unsecured Notes were issued in conjunction with exchanges and repurchases of Senior Unsecured Notes that took place in August and October 2015. The transactions were determined to be an extinguishment of each of the Senior Unsecured Notes exchanged. As such, the newly-issued Convertible Senior Unsecured Notes were recorded at fair value on the date of issuance. The Convertible Senior Unsecured Notes were guaranteed by the same Guarantors that guaranteed the Senior Unsecured Notes and were subject to covenants and bore payment terms substantially identical to those of the corresponding series of Senior Unsecured Notes of similar tenor, other than the conversion features, described further below, and the extension of the final maturity by one day. The Company accrued interest on its Convertible Senior Unsecured Notes at a fixed rate through the date of the Chapter 11 filings, with no interest accrued subsequent to the filings.

During the Predecessor 2016 Period, holders of $200.5 million aggregate principal amount ($67.4 million net of discount and including holders’ conversion feature) of 8.125% Convertible Senior Notes due 2022 and $31.6 million aggregate principal amount ($10.4 million net of discount and holders’ conversion feature) of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 84.4 million shares of Company common stock and aggregate cash payments of $33.5 million for accrued interest and early conversion payments. The conversions resulted in a gain on extinguishment of debt totaling $41.3 million, including the write off of $4.3 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for the Predecessor 2016 Period.

During the year ended December 31, 2015, holders of $186.6 million aggregate principal amount ($54.4 million net of discount and including holders’ conversion feature) of 8.125% Convertible Senior Notes due 2022 and $68.7 million aggregate principal amount ($19.3 million net of discount and holders’ conversion feature) of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 92.8 million shares of Company common stock and aggregate cash payments of $30.5 million for accrued interest and early conversion payments. The conversions resulted in a gain on extinguishment of debt totaling $6.1 million, including the write off of $5.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for year ended December 31, 2015.

Maturities of Long-Term Debt

As of December 31, 2016, $268.8 million of long-term debt will contractually mature in 2020 and $35.0 million, plus any unpaid interest on the New Building Note, will mature in 2021.

12. Derivatives

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts at fair value. Changes in derivative contract fair values are recognized in earnings.

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. The Company seeks to manage this risk through the use of commodity derivative contracts, which allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. 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. Cash settlements and valuation gains and losses on commodity derivative contracts are included in loss (gain) on derivative contracts in the consolidated statements of operations. Commodity derivative contracts are

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Notes to Consolidated Financial Statements - (Continued)

settled on a monthly or quarterly basis. Derivative assets and liabilities arising from the Company’s commodity derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheets. At December 31, 2016, the Company’s commodity derivative contracts consisted of fixed price swaps under which the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

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 settlements of contracts prior to their contractual maturity (“early settlements”) after the Chapter 11 filings occurred, resulting in $17.9 million of cash receipts.

The Company recorded gain on commodity derivative contracts of $73.1 million and $334.0 million for the years ended December 31, 2015 and 2014, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(327.7) million and $32.3 million, respectively. Included in the net cash payments for 2014 are $69.9 million of cash payments related to early settlements primarily as a result of the sale of the Gulf Properties in February 2014.

Derivatives Agreements with Royalty Trusts. During the years ended December 31, 2015 and 2014, the Company was party to derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts entered into by the Company with third parties. The derivatives agreements with the Mississippian Trust I and the Mississippian Trust II contained commodity derivative contracts that covered volumes of oil and natural gas production through December 31, 2015, and the derivatives agreement with the Permian Trust contained commodity derivative contracts that covered volumes of oil production through March 31, 2015. All activity related to the contracts underlying the derivatives agreements with the Royalty Trusts have been included in the Company’s consolidated derivative disclosures.

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, 2016, 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 New First Lien Exit Facility. The Company is not required to post additional collateral under its commodity derivative contracts as certain of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s New First Lien Exit Facility. 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 New First Lien Exit Facility and senior credit facility (in thousands):

December 31, 2016 - Successor

	Gross Amounts		Gross Amounts Offset		Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	—	$	—	$	—	$	—		$	—
Derivative contracts - noncurrent	—		—		—		—			—
Total	$	—	$	—	$	—	$	—		$	—
Liabilities
Derivative contracts - current	$	27,538	$	—	$	27,538	$	(27,538	)	$	—
Derivative contracts - noncurrent	2,176		—		2,176		(2,176		)	—
Total	$	29,714	$	—	$	29,714	$	(29,714	)	$	—

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Notes to Consolidated Financial Statements - (Continued)

December 31, 2015 - Predecessor

	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Liabilities
Derivative contracts - current	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—

At December 31, 2016, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2017 - December 2017	3,285	$	52.24
January 2018 - December 2018	1,825	$	55.34

Natural Gas Price Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2017 - December 2017	32,850	$	3.20
January 2018 - December 2018	3,650	$	3.12

Predecessor Debt - Embedded Derivatives

Debt Holder Conversion Feature. As discussed further in Note 6 and Note 11, the Convertible Senior Unsecured Notes contained a conversion feature that was exercisable at the holders’ option. This conversion feature was identified as an embedded derivative as the feature (i) possessed economic characteristics that were not clearly and closely related to the economic characteristics of the host contract, the Convertible Senior Unsecured Notes, and (ii) separate, stand-alone instruments with the same terms would have qualified as derivative instruments. As such, the holders’ conversion feature was bifurcated and accounted for separately from the Convertible Senior Unsecured Notes. The holders’ conversion feature was recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statement of operations for the Predecessor 2016 Period and the year ended December 31, 2015. Subsequent to the Chapter 11 filings, the value of the debt holder conversion features was written off and is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period.

Mandatory Prepayment Feature - PGC Senior Secured Notes. As discussed further in Note 6 and Note 11, the Senior Secured Notes contained a mandatory prepayment feature that was triggered if the outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeded $100.0 million on October 15, 2019. With respect to the PGC Senior Secured Notes, which were issued at a substantial discount, this mandatory prepayment feature was identified as an embedded derivative as the feature (i) possessed economic characteristics that were not clearly and closely related to the economic characteristics of the host contract, the PGC Senior Secured Notes, and (ii) separate, stand-alone instruments with the same terms would have qualified as derivative instruments. As such, the mandatory prepayment feature contained in the PGC Senior Secured Notes was bifurcated and accounted for separately from those notes. The mandatory prepayment feature contained in the PGC Senior Secured notes was recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statements of operations for the Predecessor 2016 Period and the year ended December 31, 2015. Subsequent to the Chapter 11 filings, the value of the mandatory prepayment feature was written off and is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period.

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Notes to Consolidated Financial Statements - (Continued)

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):

		Successor			Predecessor
		December 31,			December 31,
Type of Contract	Balance Sheet Classification	2016			2015
Derivative assets
Oil price swaps	Derivative contracts - current	$	—		$	68,224
Oil collars—three way	Derivative contracts - current	—			17,300
Derivative liabilities
Oil price swaps	Derivative contracts - current	(13,395		)	—
Natural gas price swaps	Derivative contracts - current	(14,143		)	—
Natural gas basis swaps	Derivative contracts - current	—			(1,748		)
Debt holder conversion feature	Current maturities of long-term debt	—			(29,355		)
Mandatory prepayment feature - PGC Senior Secured Notes	Current maturities of long-term debt	—			(2,941		)
Oil price swaps	Derivative contracts - noncurrent	(2,105		)	—
Natural gas price swaps	Derivative contracts - noncurrent	(71		)	—
Total net derivative contracts		$	(29,714	)	$	51,480

See Note 6 for additional discussion of the fair value measurement of the Company’s derivative contracts and Note 11 for discussion of the debt holder conversion and mandatory prepayment features.

13. Asset Retirement Obligations

The following table presents the balance and activity of the asset retirement obligations (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning balance	$	92,413		$	103,578		$	54,402		$	424,117
Liability incurred upon acquiring and drilling wells	121			505			1,662			4,968
Revisions in estimated cash flows(1)	12,397			—			44,060			(5,848		)
Liability settled or disposed in current period(2)	(540		)	(36,979		)	(1,023		)	(377,927		)
Accretion	2,090			4,365			4,477			9,092
Impact of fresh start accounting	—			20,944			—			—
Ending balance	106,481			92,413			103,578			54,402
Less: current portion	66,154			65,678			8,399			—
Asset retirement obligations, net of current	$	40,327		$	26,735		$	95,179		$	54,402

____________________

(1) Revisions for the Successor 2016 Period and the year ended December 31, 2015 relate primarily to changes in estimated well lives.

(2) Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016. Liability settled or disposed for the year ended December 31, 2014, includes $366.0 million associated with the Gulf Properties sold in February 2014. For further discussion of the sale of properties see Note 5.

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14. Commitments and Contingencies

Employee Termination Benefits. Certain employees received termination benefits, including severance and accelerated stock vesting, upon separation of service from the Company during the years ended December 31, 2016, 2015 and 2014. Employee termination benefits were $12.3 million for the Successor 2016 Period, with approximately $5.7 million accrued at December 31, 2016 for payment in the first quarter of 2017 and $18.4 million for the Predecessor 2016 Period, primarily as a result of reductions in workforce. For the years ended December 31, 2015 and 2014, employee termination benefits were $12.5 million and $8.9 million, respectively, primarily as a result of a reduction in workforce and executives’ separation from employment, and the sale of the Gulf Properties.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which depend on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company enters into commodity derivative arrangements in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 12 for the Company’s open oil and natural gas commodity derivative contracts.

The Company historically has depended on cash flows from operating activities and, as necessary, borrowings under its senior credit facility to fund its capital expenditures. Based on its cash balances, cash flows from operating activities and net borrowing availability under the New First Lien Exit Facility, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2017; however, oil or natural gas prices decline from current levels, they would have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. The Company subsequently refinanced the New First Lien Exit Facility in February 2017. See Note 21 for additional discussion.

Litigation and Claims

Chapter 11 Proceedings

The Plan in the Chapter 11 Cases discharged claims, including claims related to litigation proceedings against the Company that arose before such date. The Plan generally treated such claims as general unsecured claims that will receive only partial distribution of the amounts of consideration set aside for such claims under the Plan, which consists of cash, shares of New Common Stock and Warrants, once their amounts, if any, are finally determined by the Bankruptcy Court or otherwise. The effectiveness of the Plan also resulted in the release of certain claims held by the Company against various parties to the restructuring and related parties, including certain of the Company’s current and former officers and former directors. See Note 1 for further discussion about the Company’s Bankruptcy Petitions and the Chapter 11 Cases.

To the extent that a claim related to a pre-petition proceeding or action is not characterized as a pre-petition general unsecured claim, the Company does not believe that such claim would be material, although the anticipated resolution of any such proceeding or action is inherently unpredictable.

Successor Claims

On October 14, 2016, Lisa West and Stormy Hopson filed a class action complaint in the United States District Court for the Western District of Oklahoma against SandRidge Exploration and Production, LLC, among other defendants. In their complaint, plaintiffs assert various tort claims seeking relief for damages allegedly incurred by the plaintiffs and the proposed class for injury to property and for the purchase of insurance policies allegedly needed by the plaintiffs and the proposed class for seismic activity allegedly caused by the defendants’ operation of wastewater disposal wells. An estimate of reasonably probable losses associated with this action cannot be made at this time. The Company had not established any reserves relating to this action.

Predecessor Claims

As previously disclosed, on February 4, 2015, the staff of the Securities and Exchange Commission (the “SEC”) Enforcement Division in Washington, D.C., notified the Company that it had commenced an informal inquiry concerning the Company’s accounting for, and disclosure of, its CO₂ delivery shortfall penalties under the terms of the Gas Treating and CO₂ Delivery Agreement, dated June 29, 2008, between SandRidge Exploration and Production, LLC, and Oxy USA Inc. Additionally, the Company received a letter from an attorney for a former employee at the Company (the “Former Employee”). In the letter,

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

the attorney alleged, among other things, that the Former Employee had been terminated because he had objected to the levels of oil and gas reserves disclosed by the Company in its public filings. Over 85% of such reserves were calculated by an independent petroleum engineering firm. The Audit Committee of the Company’s pre-emergence Board of Directors retained an independent law firm to review the Former Employee’s allegations and the circumstances of the Former Employee’s termination. In addition, the Company reported the Former Employee’s allegations to the SEC staff, which thereafter issued two subpoenas to the Company relating to the Former Employee’s allegations. Counsel for the Audit Committee responded to both of these subpoenas. During the course of the above inquiries, the SEC issued a subpoena to the Company seeking documents relating to employment-related agreements between the Company and certain employees. The Company cooperated with this inquiry and, after discussion with the staff, the Company sent corrective letters to certain current and former employees who had entered into agreements containing language that may have been inconsistent with SEC rules prohibiting a company from impeding an individual from communicating directly with the SEC about possible securities law violations. The Company also updated its Code of Conduct and other relevant policies.

On June 16, 2016, the SEC filed a proof of claim in the Company’s Chapter 11 Cases in the amount of $1.2 million as a result of the SEC staff’s inquiry concerning employment-related agreements. As a result of the SEC’s proof of claim, the Company established a $1.4 million reserve for this matter.

On December 20, 2016, the Company and the SEC settled both the inquiry involving employment-related agreements and the inquiry involving the termination of the Former Employee. Pursuant to the settlement agreement, the Company agreed to pay a fine in the amount of $1.4 million. The fine will be treated as a general unsecured claim under the Plan and, as such, the Company expects to pay approximately $0.1 million to resolve these two inquiries. The Company neither admitted nor denied any violations as part of the settlement agreement. Additionally, the SEC informed the Company that as part of the settlement agreement, the SEC would not be recommending charges against the Company with regard to its pre-petition disclosures of the CO2 delivery shortfall penalties under the Company’s agreement with Oxy USA Inc., or with regard to the Company’s pre-petition processes and disclosures related to its reserves.

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.

15. Equity

Successor Equity

New Common Stock. As discussed in Note 1, on the Emergence Date, the Company issued an aggregate of approximately 18.9 million shares of its New Common Stock, par value $0.001 per share, to the holders of allowed claims, as defined in the Plan, and approximately 0.4 million shares of New Common Stock were reserved for future distributions under the Plan. Additionally, during the Successor 2016 Period, voluntary conversions of New Convertible Notes resulted in the issuance of New Company Stock. See Note 11 for further discussion of the New Convertible Notes.

Warrants. As discussed in Note 1, on the Emergence Date, the Company issued approximately 4.9 million Series A Warrants, 4.5 million of which was issued immediately upon emergence and 2.1 million Series B Warrants, 1.9 million of which was issued immediately upon emergence, that were initially exercisable for one share of New 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, to certain holders of general unsecured claims as defined in the Plan. The Warrants are exercisable from the Emergence Date until October 4, 2022. The Warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. 

Unregistered Sales of Equity Securities. The Company relied on Section 1145(a)(1) of the Bankruptcy Code as an exemption from the registration requirements of the Securities Act for the issuance of the New Common Stock, the New Convertible Notes and the Warrants. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of reorganization from registration under Section 5 of the Securities Act and state laws if three principal requirements are satisfied:

• the securities must be issued under a plan of reorganization by the debtor, its successor under a plan, or an affiliate participating in a joint plan of reorganization with the debtor;

• the recipients of the securities must hold a claim against, an interest in, or a claim for administrative expense in the case concerning the debtor or such affiliate; and

• the securities must be issued either (a) in exchange for the recipient’s claim against, interest in or claim for administrative expense in the case concerning the debtor or such affiliate or (b) principally in such exchange and partly for cash or property.

F-44

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Treasury Stock. The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and withhold a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The number of shares withheld for taxes and the associated value of those shares for the Successor 2016 Period were insignificant. These shares were accounted for as treasury stock when withheld, and then immediately retired.

Predecessor Equity

Preferred Stock. As discussed in Note 1, on the Emergence Date the Company’s authorized 7.0% and 8.5% convertible perpetual preferred stock was canceled and released under the Plan without receiving any recovery on account thereof.

Each outstanding share of convertible perpetual preferred stock was convertible at the holder’s option at any time into shares of the Company’s common stock at the specified conversion rate, subject to customary adjustments in certain circumstances.Each holder was entitled to an annual dividend payable semi-annually in cash, common stock or a combination thereof, at the Company’s election. The Company could cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the prevailing conversion rate dependent on certain factors, including the Company’s stock trading above specified prices for a set period. The convertible perpetual preferred stock was not redeemable by the Company at any time. For the year ended December 31, 2015, approximately 0.2 million shares were converted into approximately 3.0 million shares of the Predecessor Company’s common stock. The following table summarizes information about each series of the Predecessor Company’s convertible perpetual preferred stock outstanding at December 31, 2015:

	Convertible Perpetual Preferred Stock
	8.5%		7.0%
Liquidation preference per share	$	100.00	$	100.00
Annual dividend per share	$	8.50	$	7.00
Conversion rate per share to common stock	12.4805		12.8791

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.

In the first quarter of 2016, prior to the February semi-annual dividend payment date, the Company announced the suspension of the semi-annual dividend on its 8.5% convertible perpetual preferred stock. The Company suspended payment of the cumulative dividend on its 7.0% convertible perpetual preferred stock during the third quarter of 2015. The final dividend payment for the previously outstanding 6.0% convertible preferred stock was made during 2014, as it fully converted to common stock in 2014. 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.

F-45

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Preferred stock dividend payments and accruals for the Company’s 8.5%, 7.0% and 6.0% convertible perpetual preferred stock are as follows (in thousands):

	Predecessor
	Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
8.5% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	11,262	$	22,525
Dividends satisfied in shares of common stock(1)	$	—	$	11,262	$	—
Accrued dividends at period end	$	—	$	8,447	$	8,447
Dividends in arrears	$	11,262	$	—	$	—
7.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	—	$	21,000
Dividends satisfied in shares of common stock(2)	$	—	$	10,500	$	—
Accrued dividends at period end	$	—	$	13,125	$	2,625
Dividends in arrears	$	21,000	$	10,500	$	—
6.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	—	$	12,000
Accrued dividends at period end	$	—	$	—	$	—

____________________

(1) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 18.6 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, ($3.58 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

(2) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 5.7 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, ($2.23 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

Paid and unpaid dividends included in the calculation of (loss applicable) income available to the Company’s common stockholders and the Company’s basic (loss) earnings per share calculation for the Predecessor 2016 Period and years ended December 31, 2015 and 2014 are presented in the accompanying consolidated statements of operations.

See Note 19 for discussion of the Company’s (loss) earnings per share calculation.

Common Stock. As discussed in Note 1, on the Emergence Date the Company’s authorized common stock was canceled and released under the Plan without receiving any recovery on account thereof.

In June 2015, the Company's stockholders approved an amendment to the Company's Certificate of Incorporation, to increase the number of shares of capital stock the Company is authorized to issue from 850.0 million (800.0 million shares of common stock and 50.0 million shares of preferred stock), par value $0.001 to 1.85 billion (1.80 billion shares of common stock and 50.0 million shares of preferred stock), par value $0.001. The Company had 2.1 million shares of common stock held in treasury at December 31, 2015.

Redemption of Senior Unsecured Notes. During the year ended December 31, 2015, the Company issued approximately 28.0 million shares of common stock in exchange for $50.0 million in Senior Unsecured Notes. See Note 11 for additional discussion of the redemption of Senior Unsecured Notes.

F-46

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Conversions of Convertible Senior Unsecured Notes. During the Predecessor 2016 Period and year ended December 31, 2015, the Company issued approximately 84.4 million and 92.8 million shares, respectively, of common stock upon the exercise of conversion options by holders of approximately $232.1 million and $255.3 million in par value, respectively, of the Convertible Senior Unsecured Notes. The Company recorded the issuance of common shares at fair value on the various dates the exchanges occurred. See Note 11 for additional discussion of the Convertible Senior Unsecured Notes transactions.

See Note 16 for discussion of the Company’s share-based compensation.

Treasury Stock. 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.

	Predecessor
	Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Number of shares withheld for taxes	1,122		1,872		1,034
Value of shares withheld for taxes	$	44	$	2,428	$	6,373

Prior to the Emergence Date, shares of Predecessor Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan were accounted for as treasury shares. These shares were not included as outstanding shares of common stock for accounting purposes, and were canceled on the Emergence Date. No further matching contributions will be made to the non-qualified deferred compensation plan by the Successor Company.

Stockholder Receivable. The Predecessor Company was party to a settlement agreement relating to a third-party claim against its former CEO under Section 16(b) of the Securities Exchange Act of 1934, as amended. At December 31, 2015, the remaining $1.3 million receivable related to this settlement was classified as a component of additional paid-in capital in the accompanying consolidated balance sheet. In accordance with the Plan, the remaining balance of this receivable was fully discharged on the Emergence Date.

16. Share-Based Compensation

As discussed in Note 1, the Predecessor Company’s common stock was canceled and New Common Stock was issued on the Emergence Date. Accordingly, the Predecessor Company's then existing share-based compensation awards were also canceled, which resulted in the recognition of any previously unamortized expense related to the canceled 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.Pursuant to terms of the Plan, the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) became effective on the Emergence Date.

The Successor Company’s board of directors or any committee duly authorized thereby, will administer the Omnibus Incentive Plan. The committee has broad authority under the Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award.

Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors, employees of the Successor Company or any of its affiliates, and certain consultants and advisors to the Successor 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 New Common Stock, as well as certain cash-based awards.

The maximum number of shares of New Common Stock that may be issued or transferred pursuant to awards under the Omnibus Incentive Plan is approximately 4.6 million. If any stock option or other stock-based award granted under the Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of New Common Stock underlying any unexercised award shall again be available for the purpose of awards under the Omnibus Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of New Common Stock awarded under the Plan are forfeited for any reason, the number of forfeited shares shall again be available for

F-47

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

purposes of awards under the Omnibus Incentive Plan. Any award under the Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation.

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s stockholders.

Restricted Common Stock Awards. During October 2016, awards for approximately 1.4 million shares of restricted stock were granted under the Omnibus Incentive Plan. These restricted shares will vest over a three year period. The Successor Company recognized share-based compensation expense of $6.6 million, net of $0.3 million capitalized, for the Successor 2016 Period. Additionally, share-based compensation expense for the Successor 2016 Period includes $4.3 million for the accelerated vesting of 0.2 million restricted common stock awards related to the Successor Company’s reduction in workforce during the fourth quarter of 2016. 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	—		$	—
Granted	1,448		$	24.32
Vested	(14	)	$	24.32
Forfeited / Canceled	(27	)	$	24.32
Unvested restricted shares outstanding at December 31, 2016	1,407		$	24.32

As of December 31, 2016, the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $27.1 million. The remaining weighted-average contractual period over which this compensation cost may be recognized is 2.8 years. The Successor Company’s restricted stock awards are equity-classified awards.

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, 2013	7,643		$	6.92
Granted	6,367		$	6.17
Vested	(3,432	)	$	7.04
Forfeited / Canceled	(2,022	)	$	6.60
Unvested restricted shares outstanding at December 31, 2014	8,556		$	6.39
Granted	2,928		$	0.88
Vested	(5,186	)	$	4.95
Forfeited / Canceled	(672	)	$	6.38
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85
Granted	—		$	—
Vested	(3,034	)	$	5.34
Forfeited / Canceled	(2,592	)	$	4.31
Predecessor ending unvested restricted shares at October 1, 2016	—		$	—

F-48

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

The Predecessor Company issued share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the SandRidge Energy, Inc. 2009 Incentive Plan, (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 share-based compensation expense of $11.2 million, net of $1.7 million capitalized, for the Predecessor 2016 Period, and $21.7 million and $22.6 million, net of $5.9 million and $6.0 million capitalized for the years ended December 31, 2015 and 2014, respectively. 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.

In conjunction with the cancellation of the Predecessor Company’s common stock and termination of the 2009 Plan on the Emergence Date, the unrecognized compensation cost related to the Predecessor Company’s unvested restricted common stock awards of $5.9 million was expensed.

17. Incentive and Deferred Compensation Plans

Performance Incentive Plan. In January 2016, the Company implemented a performance incentive plan. The plan replaced, on a prospective basis, the Company’s previous annual incentive plan, including 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 payouts with a cash make up payment for above target performance based on the Company’s annual performance results to be made in the first quarter of 2017. 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, with approximately $15.8 million accrued at December 31, 2016 for payment in the first quarter of 2017.

Annual Incentive Plan. Prior to January 2016, for certain members of management, the annual incentive plan incorporated objective performance criteria, individual performance goals and competitive target award levels for the 2015 performance year with payout percentages ranging from 0% to 200% of specified target levels based on actual performance. As of December 31, 2015, the Company had accrued approximately $21.6 million for the annual incentive for all employees, including an accrual for an annual incentive for specified members of management based on actual performance compared to target levels specified in the annual incentive plan, which was paid in the first quarter of 2016.

Deferred Compensation Plans. 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 Internal Revenue Service (“IRS”) regulations. For the Successor 2016 Period, the Successor Company made matching cash contributions to the plan equal to 100% on the first 10% employee deferred wages for the period totaling $0.9 million. For the Predecessor 2016 Period, the Predecessor Company made matching cash contributions to the plan equal to 100% on the first 10% employee deferred wages for the period totaling$4.9 million. For the years endedDecember 31, 2015and2014, the Predecessor Company made matching contributions to the plan through cash purchases of Predecessor Company stock equal to 100% on the first 10% employee deferred wages. Retirement plan expense for the years ended December 31, 2015 and 2014 was approximately $7.9 million and $8.7 million, respectively. 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.

The Company maintains 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 Predecessor Company made insignificant matching contributions on non-qualified contributions for the Successor 2016 Period, the Predecessor 2016 Period and years ended December 31, 2015 and 2014. On December 31, 2016, the Successor Company began the process of terminating the non-qualified deferred compensation plan. No employee or employer contributions will be made to the plan after December 31, 2016 and in accordance with the plan termination procedures, the remaining assets held in the plan, of approximately $7.5 million as of December 31, 2016, will be fully distributed to participating employees throughout 2017 and the first quarter of 2018.

Any assets placed in trust by the Company to fund future obligations of the Company’s non-qualified deferred compensation plan are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their own deferred compensation in, and the Company’s contributions to, the plan.

F-49

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

18. Income Taxes

The Company’s income tax provision (benefit) consisted of the following components (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Current
Federal	$	—	$	—	$	—	$	(1,160	)
State	9		11		123		(1,133		)
	9		11		123		(2,293		)
Deferred
Federal	—		—		—		—
State	—		—		—		—
	—		—		—		—
Total provision (benefit)	9		11		123		(2,293		)
Less: income tax provision attributable to noncontrolling interest	—		—		90		283
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	9	$	11	$	33	$	(2,576	)

A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax provision (benefit) is as follows (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Computed at federal statutory rate	$	(116,891	)	$	504,283		$	(1,512,325	)	$	122,362
State taxes, net of federal benefit	(3,696		)	10,512			(19,988		)	4,145
Non-deductible expenses	144			462			816			1,895
Non-deductible debt costs	—			22,694			10,228			—
Stock-based compensation	306			5,884			6,700			1,467
Net effects of consolidating the non-controlling interests’ tax provisions	—			—			218,196			(34,614		)
Discharge of debt and other reorganization related items	—			359,278			—			—
Change in valuation allowance	120,144			(903,102		)	1,296,405			(96,769		)
Other	2			—			1			(1,062		)
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	9		$	11		$	33		$	(2,576	)

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. As of December 31, 2016, 2015 and 2014 the balance of the valuation allowance was $1.1 billion, $2.0 billion, and $649.6 million, respectively. 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. 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 net deferred tax asset at December 31, 2016. Thus, the Company’s effective tax rate and tax expense for the Successor 2016 Period and Predecessor 2016 Period continue to be low as a result of the Company not recognizing an income tax benefit associated with its net (loss) income from the same periods.

F-50

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):

	Successor			Predecessor
	December 31, 2016			December 31, 2015
Deferred tax liabilities
Investments(1)	$	275,128		$	138,310
Derivative contracts	—			30,989
Long-term debt	—			10,017
Total deferred tax liabilities	275,128			179,316
Deferred tax assets
Property, plant and equipment	751,683			807,275
Derivative contracts	11,274			—
Allowance for doubtful accounts	1,487			18,702
Net operating loss carryforwards	527,079			1,190,799
Compensation and benefits	14,494			18,607
Alternative minimum tax credits and other carryforwards	43,770			44,302
Asset retirement obligations	40,399			38,314
CO2 under-delivery shortfall penalty	—			40,654
Other	4,663			4,305
Total deferred tax assets	1,394,849			2,162,958
Valuation allowance	(1,119,721		)	(1,983,642		)
Net deferred tax liability	$	—		$	—

____________________

(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.

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 discussed in Note 1, on the Emergence Date the Company’s existing convertible perpetual preferred stock and the Company’s common stock were canceled and New Common Stock was issued resulting in the Company experiencing an ownership change under IRC Section 382. Further, certain of the transactions that occurred upon the Company’s emergence from bankruptcy on October 4, 2016 materially impacted the Company’s tax attributes. Cancellation of indebtedness income resulting from these transactions reduced the Company’s tax attributes, including but not limited to federal net operating loss carryforwards, in the amount of $3.7 billion. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the October 4, 2016 ownership change and cancellation of indebtedness income on its tax attributes. Upon filing its 2016 U.S. Federal income tax return, the Company plans to elect an available alternative that does not subject existing tax attributes to an IRC Section 382 limitation. However, should an additional ownership change become likely to occur prior to filing its 2016 U.S. Federal income tax return, the Company will evaluate the remaining available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation which could result in some or all of the remaining net operating loss carryforwards expiring unused. The ownership change did not result in a current federal tax liability at December 31, 2016.

As of December 31, 2016, the Company had approximately $9.3 million of alternative minimum tax credits available that do not expire. In addition, the Company had approximately $1.3 billion of federal net operating loss carryovers after attribute reduction resulting from cancellation of indebtedness that expire during the years 2028 through 2036.

F-51

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

At December 31, 2016 and 2015, the Company had a liability of approximately $0.1 million for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015
Unrecognized tax benefit at January 1	$	81	$	81	$	77
Changes to unrecognized tax benefits related to a prior year	3		—		4
Unrecognized tax benefit at December 31	$	84	$	81	$	81

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, 2016, 2015 and 2014. The Company does not expect a significant change in its gross unrecognized tax benefits balance within the next 12 months.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2013 to present remain open for federal examination. Additionally, tax years 2005 through 2012 remain subject to examination for the purpose of determining the amount of federal net operating loss and other carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years.

F-52

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

19. (Loss) Earnings per Share

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

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)
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(1)	—			—
Warrants(1)	—			—
New Convertible Notes(2)	—			—
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(3)	—			—
Diluted earnings per share	$	1,424,476		708,928	$	2.01
Year Ended December 31, 2015 (Predecessor)
Basic loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Effect of dilutive securities
Restricted stock and units(3)	—			—
Convertible preferred stock(4)	—			—
Convertible senior unsecured notes(5)	—			—
Diluted loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Year Ended December 31, 2014 (Predecessor)
Basic earnings per share	$	203,260		479,644	$	0.42
Effect of dilutive securities
Restricted stock	—			2,181
Convertible preferred stock(4)	6,500			17,918
Diluted earnings per share	$	209,760		499,743	$	0.42

____________________

(1) No incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive.

(2) Potential common shares related to the New 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.

(3) No incremental shares of potentially dilutive restricted stock awards or units were included for the Predecessor 2016 Period and the year ended December 31, 2015 as their effect was antidilutive under the treasury stock method.

(4) Potential common shares related to the Predecessor Company’s then-outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.2 million and 71.7 million shares for the years ended December 31, 2015 and 2014, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.

(5) Potential common shares related to the Predecessor Company’s then-outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 48.5 million shares for the year ended December 31, 2015 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

See Note 15 for discussion of the Predecessor Company’s convertible perpetual preferred stock. The remaining outstanding New Convertible Notes were converted into shares of New Common Stock as a result of the Company’s entry into the refinanced credit facility on February 10, 2017. For further discussion see Note 21.

F-53

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

20. Related Party Transactions

The Company entered into transactions in the ordinary course of business with certain related parties. These transactions primarily consisted of sales of oil and natural gas. See Note 10 for accounts payable attributable to related party transactions.

2014 Divestiture. See Note 5 for discussion of the sale of the Gulf Properties to Fieldwood and the Company’s guarantee on behalf of Fieldwood of certain associated plugging and abandonment obligations associated with the Gulf Properties. Fieldwood is a portfolio company of Riverstone Holdings LLC, affiliates of which owned a significant number of shares of the Predecessor Company’s common stock at the time the transaction occurred.

21. Subsequent Events

Acquisition of Properties. On February 10, 2017, the Company acquired approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash. Also included in the acquisition were working interests in 4 wells previously drilled on the acreage.

Refinancing of New First Lien Exit Facility. On February 10, 2017, the New First Lien Exit Facility was refinanced into a new $600.0 million credit facility with a $425.0 million borrowing base. The amended credit facility agreement had the following impacts:

• increased the principal amount of commitments to $600.0 million from $425.0 million;

• extended the maturity date to March 31, 2020 from February 4, 2020;

• borrowing base determinations now include the Company’s proportionately consolidated share of proved reserves held by the Royalty Trusts;

• reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to 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;

• reduced the LIBOR floor from 1% to 0%;

• eliminated the minimum proved developing producing reserves asset coverage ratio;

• removed the requirement to maintain $50.0 million in a cash collateral account controlled by the administrative agent;

• eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and

• eliminated certain negative covenants, such as the $20.0 million liquidity requirement and the limitation on capital expenditures.

Conversions of New Convertible Notes to New Common Stock. During the period from January 1, 2017 to February 9, 2017, holders of approximately $5.1 million in aggregate principal amount of the New Convertible Notes exercised conversion options applicable to those notes, resulting in the issuance of approximately 0.3 million shares of New Common Stock.

In conjunction with the refinancing of the New First Lien Exit Facility that took place on February 10, 2017, the remaining $263.7 million par value of the New Convertible Notes mandatorily converted into approximately 14.1 million shares of New Common Stock.

F-54

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

22. Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

The supplemental information 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):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015			2014
Oil and natural gas properties
Proved	$	840,201		$	12,529,681		$	11,707,147
Unproved	74,937			363,149			290,596
Total oil and natural gas properties	915,138			12,892,830			11,997,743
Less accumulated depreciation, depletion and impairment	(353,030		)	(11,149,888		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	$	562,108		$	1,742,942		$	5,638,594

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):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Acquisitions of properties
Proved	$	5,142	$	3,897	$	35,376	$	73,370
Unproved	5,491		1,899		210,065		123,649
Exploration(1)	—		1,234		29,297		41,070
Development	27,429		149,924		571,562		1,288,395
Total cost incurred	$	38,062	$	156,954	$	846,300	$	1,526,484

____________________

(1) Includes seismic costs of $7.1 million and $10.8 million for the years ended December 31, 2015 and 2014, respectively.

F-55

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Results of Operations for Oil and Natural Gas Producing Activities

The Company’s results of operations from oil and natural gas producing activities are shown in the following table (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Revenues	$	98,307		$	279,971		$	707,434		$	1,420,879
Expenses
Production costs	27,640			135,715			324,141			377,819
Depreciation and depletion	33,971			86,613			319,913			434,295
Accretion of asset retirement obligations	2,090			4,365			4,477			9,092
Impairment	319,087			657,392			4,473,787			164,779
Total expenses	382,788			884,085			5,122,318			985,985
(Loss) income before income taxes	(284,481		)	(604,114		)	(4,414,884		)	434,894
Income tax expense (benefit)(1)	8			(5		)	126			(2,852		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	(284,489	)	$	(604,109	)	$	(4,415,010	)	$	437,746

____________________

(1) Reflects the Company’s effective tax rate for each period.

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 such as the future prices of oil, natural gas and NGLs; 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 table below 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 with the SEC’s regulations. Estimates of the substantial majority of the Company’s proved reserves have been prepared by

F-56

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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, Inc. (“CG&A”), Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2016, 2015 and 2014. CG&A, 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. CG&A and Ryder Scott prepared the estimates of proved reserves for a majority of the Company’s properties as of December 31, 2016. The remaining 6.0% of estimates of proved reserves was 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.

2016 Activity. During 2016, on a pro forma combined basis, 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.

2015 Activity. During 2015, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 9.7 MMBbls, 9.3 MMBbls, and 160.9 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Acquisition of the Rockies assets, located in Jackson County, Colorado, in December 2015 added 27.6 MMBoe of reserves. These positive revisions were offset by (i) negative pricing revisions of approximately 54 MMBbls for oil, 36 MMBbls for NGLs and 687 Bcf for natural gas, due primarily to significantly lower commodity prices in 2015, and (ii) negative revisions of approximately 16 MMBbls for oil, 1 MMBbls for NGLs and 74 Bcf for natural gas primarily from well performance in the Mid-Continent.

2014 Activity. During 2014, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 37.6 MMBbls, 27.5 MMBbls, and 467.2 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Revisions of previous estimates decreased oil reserves by 18.7 MMBbls, primarily comprised of (i) approximately 9 MMBbls from Permian Basin proved undeveloped reserves, largely due to removal of drilling locations not expected to be drilled within a five year period, (ii) approximately 8 MMBbls from well performance in the Mid-Continent and (iii) approximately 2 MMBbls from acreage losses or revisions to well interest ownerships. These negative revisions were offset by positive revisions to NGL and gas reserves of 11.1 MMBbls and 167.6 Bcf, respectively, primarily from well performance in the Mid-Continent area. Acquisitions of reserves added 3.5 MMBoe.

Sales of proved reserves during 2014 totaled 55.5 MMBoe from the sale of the Gulf Properties.

F-57

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

The summary below presents changes in the Company’s estimated reserves.

	Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2013 - Predecessor	142,641		59,052		1,390,429
Revisions of previous estimates	(18,687	)	11,103		167,589
Acquisitions of new reserves	1,009		441		12,527
Extensions and discoveries	37,603		27,500		467,185
Sales of reserves in place	(25,659	)	(2,516	)	(163,800	)
Production	(10,876	)	(3,794	)	(85,697	)
As of December 31, 2014(2) - Predecessor	126,031		91,786		1,788,233
Revisions of previous estimates	(70,708	)	(37,384	)	(759,106	)
Acquisitions of new reserves	22,447		2,460		15,952
Extensions and discoveries	9,741		9,257		160,865
Production	(9,600	)	(5,044	)	(92,104	)
As of December 31, 2015(2) - Predecessor	77,911		61,075		1,113,840
Adoption of ASU 2015-02	(6,971	)	(3,695	)	(50,508	)
Revisions of previous estimates	(39,973	)	(21,475	)	(415,568	)
Extensions and discoveries	987		472		7,955
Sales of reserves in place	(387	)	—		(145,267	)
Production	(4,315	)	(3,358	)	(44,124	)
As of October 1, 2016 - Predecessor	27,252		33,019		466,328
Revisions of previous estimates	23,978		1,139		915
Extensions and discoveries	2,868		448		10,309
Production	(1,214	)	(999	)	(12,770	)
As of December 31, 2016 - Successor	52,884		33,607		464,782
Proved developed reserves
As of December 31, 2013 - Predecessor	83,893		35,807		951,609
As of December 31, 2014 - Predecessor	79,022		56,823		1,203,447
As of December 31, 2015 - Predecessor	48,639		51,089		964,617
As of October 1, 2016 - Predecessor	24,541		30,238		428,050
As of December 31, 2016 - Successor	25,911		29,290		393,028
Proved undeveloped reserves
As of December 31, 2013 - Predecessor	58,748		23,245		438,820
As of December 31, 2014 - Predecessor	47,009		34,963		584,786
As of December 31, 2015 - Predecessor	29,272		9,986		149,223
As of October 1, 2016 - Predecessor	2,711		2,781		38,278
As of December 31, 2016 - Successor	26,973		4,317		71,754

____________________

(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	2014
Oil (MBbl)	7,004	11,027
NGL (MBbl)	3,694	4,761
Natural gas (MMcf)	50,508	70,833

F-58

SandRidge Energy, Inc. and Subsidiaries

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 12-month average market prices at December 31, 2016, 2015 and 2014 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:

	Successor		Predecessor
	December 31,		December 31,
	2016		2015		2014
Oil (per barrel)	$	38.59	$	45.29	$	91.65
NGL (per barrel)	$	10.99	$	12.68	$	32.79
Natural gas (per Mcf)	$	1.56	$	1.87	$	3.61

• 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).

	Successor			Predecessor
	December 31,			December 31,
	2016			2015			2014
Future cash inflows from production	$	3,136,762		$	6,387,944		$	21,022,320
Future production costs	(1,454,798		)	(2,731,542		)	(6,499,366		)
Future development costs(1)	(665,516		)	(838,945		)	(1,810,201		)
Future income tax expenses	(142		)	(901		)	(3,223,740		)
Undiscounted future net cash flows	1,016,306			2,816,556			9,489,013
10% annual discount	(577,942		)	(1,501,994		)	(5,401,261		)
Standardized measure of discounted future net cash flows(2)	$	438,364		$	1,314,562		$	4,087,752

____________________

(1) Includes abandonment costs.

(2) Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015 and 2014 respectively.

F-59

SandRidge Energy, Inc. and Subsidiaries

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):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning present value	$	392,604		$	1,314,562		$	4,087,752		$	4,017,611
Changes during the year
Adoption of ASU 2015-02	—			(224,965		)	—			—
Revenues less production and other costs	(70,668		)	(144,256		)	(383,293		)	(1,043,060		)
Net changes in prices, production and other costs	35,684			(394,173		)	(3,813,465		)	331,694
Development costs incurred	7,941			69,080			217,596			364,262
Net changes in future development costs	(291,232		)	436,041			273,437			(341,183		)
Extensions and discoveries	14,986			12,449			230,055			1,785,963
Revisions of previous quantity estimates	308,374			(728,254		)	(1,354,778		)	(77,688		)
Accretion of discount	9,375			91,337			512,483			477,458
Net change in income taxes	—			402			1,426,333			(256,371		)
Purchases of reserves in-place	—			—			18,429			50,958
Sales of reserves in-place	—			(13,314		)	—			(1,058,330		)
Timing differences and other(1)	31,300			(26,305		)	100,013			(163,562		)
Net change for the year	45,760			(921,958		)	(2,773,190		)	70,141
Ending present value(2)	$	438,364		$	392,604		$	1,314,562		$	4,087,752

____________________

(1) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2) Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015, and 2014 respectively.

F-60

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

23. Quarterly Financial Results (Unaudited)

The Company’s operating results for each quarter of 2016 and 2015 are summarized below (in thousands, except per share data).

	Predecessor											Successor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter		Fourth Quarter
2016
Total revenues	$	90,332		$	99,421		$	104,056		$	—	$	98,456
Loss from operations(1)(2)	$	(273,555	)	$	(275,310	)	$	(357,338	)	$	—	$	(336,345	)
Net (loss) income(1)(2)(3)	$	(313,226	)	$	(515,911	)	$	(404,337	)	$	2,674,271	(333,982		)
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(1)(2)(3)	$	(324,107	)	$	(521,351	)	$	(404,337	)	$	2,674,271	$	(333,982	)
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
Basic	$	(0.47	)	$	(0.73	)	$	(0.56	)	$	3.72	$	(17.61	)
Diluted	$	(0.47	)	$	(0.73	)	$	(0.56	)	$	3.72	$	(17.61	)

	Predecessor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2015
Total revenues	$	215,308		$	229,607		$	180,152		$	143,642
Loss from operations(4)(5)	$	(1,088,456	)	$	(1,535,083	)	$	(1,059,733	)	$	(959,406	)
Net loss(4)(5)	$	(1,151,874	)	$	(1,588,731	)	$	(796,485	)	$	(783,961	)
Loss applicable to SandRidge Energy, Inc. common stockholders(4)(5)	$	(1,045,834	)	$	(1,375,556	)	$	(649,526	)	$	(664,579	)
Loss applicable per share to SandRidge Energy, Inc. common stockholders(6)
Basic	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
Diluted	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)

____________________

(1) Includes impairment of $110.1 million, $253.6 million, $354.5 million and $319.1 million for the first, second, and third quarters and Successor 2016 Period, respectively. See Note 9 for further discussion of impairment.

(2) Includes loss on settlement of contract of $89.1 million and gain on extinguishment of $41.3 million for the first quarter.

(3) Includes (loss) gain on reorganization items related to the Company’s restructuring under Chapter 11 filings of $(200.9) million, $(42.8) million, and $2.7 billion for the second and third quarters and Predecessor fourth quarter, respectively. See Note 2 for further discussion of reorganization items.

(4) Includes impairment of $1.1 billion, $1.5 billion, $1.1 billion and $886.8 million for the first, second, third and fourth quarters, respectively. See Note 9 for further discussion of impairment.

(5) Includes (gain) loss on derivative contracts of $(49.8) million, $33.0 million, $(42.2) million and $(14.0) million for the first, second, third and fourth quarters, respectively.

(6) Loss applicable per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of loss applicable per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

F-61

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SANDRIDGE ENERGY, INC.
	By	/s/    JAMES D. BENNETT
		James D. Bennett,
		President and Chief Executive Officer
March 3, 2017

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Julian Bott, 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	Title	Date
/s/ JAMES D. BENNETT	President, Chief Executive Officer and Director (Principal Executive Officer)	March 3, 2017
James D. Bennett
/s/ JULIAN BOTT	Chief Financial Officer and Executive Vice President (Principal Financial Officer)	March 3, 2017
Julian Bott
/s/ LISA E. KLEIN	Vice President—Accounting (Principal Accounting Officer)	March 3, 2017
Lisa E. Klein
/s/ MICHAEL L. BENNETT	Director	March 3, 2017
Michael L. Bennett
/s/ JOHN V. GENOVA	Chairman	March 3, 2017
John V. Genova
/s/ WILLIAM (BILL) M. GRIFFIN	Director	March 3, 2017
William (Bill) M. Griffin
/s/ DAVID J. KORNDER	Director	March 3, 2017
David J. Kornder

EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
2.1	Equity Purchase Agreement dated as of January 6, 2014, between SandRidge Energy, Inc., SandRidge Holdings, Inc. and Fieldwood Energy LLC	8-K	001-33784	2.1	1/9/2014
2.2	Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc., et al., dated September 19, 2016	8-A	001-33784	2.1	10/4/2016
3.1	Amended and Restated Certificate of Incorporation of SandRidge Energy, Inc.	8-A	001-33784	3.1	10/4/2016
3.2	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-A	001-33784	3.2	10/4/2016
4.1	Form of specimen Common Stock certificate of SandRidge Energy, Inc.	8-K	001-33784	4.1	10/7/2016
4.2	Warrant Agreement, dated as of October 4, 2016, between SandRidge Energy, Inc. and American Stock Transfer & Trust Company, LLC, as warrant agent	8-K	001-33784	10.6	10/7/2016
4.3	Convertible Notes Indenture, dated as of October 4, 2016, among SandRidge Energy, Inc., the guarantors party thereto and Wilmington Trust, National Association, as trustee	8-K	001-33784	10.3	10/7/2016
4.4	Registration Rights Agreement dated as of October 4, 2016, among SandRidge Energy, Inc. and the holders party thereto	8-A	001-33784	10.1	10/4/2017
10.1†	SandRidge Energy, Inc. 2016 Omnibus Incentive Plan	8-K	001-33784	10.8	10/7/2016
10.1.1†	Form of Non-employee Director Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.1.2†	Form of Executive Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.1.3†	Form of Emergence Performance Unit Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.1.4†	Form of Restricted Stock Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.1.5†	Form of Performance Share Unit Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.2.1†	Employment Agreement, effective as of August 12, 2014, between SandRidge Energy, Inc. and James D. Bennett	10-K	001-33784	10.3.1	2/27/2015
10.2.2†	Employment Agreement, effective as of August 17, 2015, between SandRidge Energy, Inc. and Julian Bott.	8-K	001-33784	10.1	8/5/2015
10.2.3†	Employment Agreement, effective as of December 30, 2013, between SandRidge Energy, Inc. and Duane Grubert	10-K	001-33784	10.3.2	2/27/2015
10.2.4†	2015 Form of Employment Agreement for Executive Vice Presidents and Senior Vice Presidents of SandRidge Energy, Inc.	10-Q	001-33784	10.3.4	11/5/2015
10.3†	Form of Indemnification Agreement for directors and officers	8-K	001-33784	10.9	10/7/2016

10.4	First Lien Exit Facility, dated as of October 4, 2016, among SandRidge Energy, Inc., the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender	8-K	001-33784	10.1	10/7/2016
10.5	Amended and Restated Credit Agreement, dated as of February 10, 2017, among SandRidge Energy, Inc., Royal Bank of Canada, as Administrative Agent, and the other lenders party thereto filed as Exhibit A to the Refinancing Amendment to the Existing Credit Agreement	8-K	001-33784	10.1	2/13/2017
10.6	Pledge and Security Agreement, dated as of October 4, 2016, by SandRidge Energy, Inc., the other grantors party thereto, and Royal Bank of Canada, as Administrative Agent					*
10.7	Intercreditor and Subordination Agreement, dated as of October 4, 2016, among SandRidge Energy, Inc., Royal Bank of Canada, as priority lien agent, and Wilmington Trust, National Association, as the subordinated collateral trustee	8-K	001-33784	10.4	10/7/2016
10.8	Collateral Trust Agreement, dated as of October 4, 2016, among SandRidge Energy, Inc., the guarantors from time to time party thereto, Wilmington Trust, National Association, as Trustee under the Indenture, the other Parity Lien Representatives from time to time party thereto and Wilmington Trust, National Association, as Collateral Trustee	8-K	001-33784	10.5	10/7/2016
10.9	Building Promissory Note dated as of October 4, 2016, between SandRidge Energy, Inc. and Fir Tree E&P Holdings II, LLC and SOLA LTD	8-K	001-33784	10.2	10/7/2016
10.9.1	Amendment No. 1 to Building Promissory Note dated as of January 27, 2017, between SandRidge Energy, Inc. and Fir Tree E&P Holdings II, LLC and SOLA LTD					*
10.10	Restructuring Support Agreement, dated as of May 11, 2016	8-K	001-33784	10.1	5/16/2016
21.1	Subsidiaries of SandRidge Energy, Inc.					*
23.1	Consent of PricewaterhouseCoopers LLP					*
23.2	Consent of Cawley, Gillespie & Associates					*
23.3	Consent of Netherland, Sewell & Associates, Inc.					*
23.4	Consent of Ryder Scott Company, L.P.					*
31.1	Section 302 Certification-Chief Executive Officer					*
31.2	Section 302 Certification-Chief Financial Officer					*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
99.1	Report of Cawley, Gillespie & Associates					*
99.2	Report of Netherland, Sewell & Associates, Inc.					*
99.3	Report of Ryder Scott Company, L.P.					*
101.INS	XBRL Instance 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					*
† Management contract or compensatory plan or arrangement

EX-10.6

Exhibit 10.6

PLEDGE AND SECURITY AGREEMENT

dated as of October 4, 2016
from
the Grantors referred to herein,
to
Royal Bank of Canada,
as Administrative Agent

Table of Contents

Page

Section 1. Terms Generally    2

Section 2. Grant of Security    3

Section 3. Security for Obligations    4

Section 4. Grantors Remain Liable    4

Section 5. Delivery and Control of Security Collateral    5

Section 6. Maintaining Deposit and Securities Accounts    7

Section 7. Representations and Warranties    8

Section 8. Further Assurances    9

Section 9. Collections on Receivables and Related Contracts    10

Section 10. As to Intellectual Property    10

Section 11. Voting Rights; Dividends; Etc    11

Section 12. Additional Shares    12

Section 13. Administrative Agent Appointed Attorney-in-Fact    12

Section 14. Administrative Agent May Perform    12

Section 15. The Administrative Agent’s Duties    12

Section 16. Remedies    13

Section 17. Subordination of Liens    15

Section 18. Amendments; Waivers; Additional Grantors; Etc    15

Section 19. Notices, Etc    15

Section 20. Continuing Security Interest; Assignments under the Credit Agreement    15

Section 21. Release; Termination    16

Section 22. Terms Generally; References and Titles    17

Section 23. Execution in Counterparts    17

Section 24. Governing Law; Jurisdiction; Waiver of Jury Trial, Etc.    17

Schedules and Exhibits

Schedule I Location, Type of Organization, Jurisdiction of Organization and Organizational Identification Number

Schedule II Pledged Equity

Exhibit A Form of Security Agreement Supplement

i

PLEDGE AND SECURITY AGREEMENT

PLEDGE AND SECURITY AGREEMENT dated as of October 4, 2016 (this “Agreement”), made by SandRidge Energy, Inc., a Delaware corporation (the “Borrower”), the other Persons listed on the signature pages hereof and the Additional Grantors (as defined in Section 18) (the Borrower, the Persons so listed and the Additional Grantors being collectively the “Grantors”), to ROYAL BANK OF CANADA, as administrative agent (the “Administrative Agent”) for the Secured Parties (as hereinafter defined).

PRELIMINARY STATEMENTS

(1)The Borrower has entered into the Credit Agreement dated as of October 4, 2016 (as amended, restated, supplemented, or otherwise modified from time to time, the “Credit Agreement”; capitalized terms defined therein and not otherwise defined herein being used herein as therein defined) with certain Lenders party thereto and Royal Bank of Canada, as administrative agent (the “Administrative Agent”).

(2)As contemplated in the Credit Agreement, the Grantors owe, and may hereafter owe Obligations to Lender Counterparties. The Swap Contracts and Treasury Management Services Agreements under which such Obligations are owed are herein called the “Lender Contracts”.

(3)The Grantors are entering into this Agreement in order to grant to the Administrative Agent for the ratable benefit of the Secured Parties a security interest in the Collateral (as hereinafter defined).

(4)Each Grantor is the owner of the shares of stock or other Equity Interests (the “Initial Pledged Equity”) set forth opposite such Grantor’s name on and as otherwise described in Schedule II hereto and issued by the Persons named therein.

(5)It is a condition precedent to the making of Loans and the issuance of Letters of Credit by the Secured Parties under the Credit Agreement and the entry into Lender Contracts from time to time, that the Grantors shall have granted the assignment and security interest and made the pledge and assignment contemplated by this Agreement.

(6)Each Grantor will derive substantial direct and indirect benefit from the transactions contemplated by the Loan Documents and the Lender Contracts.

NOW, THEREFORE, in consideration of the premises and in order to induce the Secured Parties to make Loans and issue Letters of Credit under the Credit Agreement and to induce the Secured Parties to enter into the Lender Contracts from time to time, each Grantor agrees with the Administrative Agent for the ratable benefit of the Secured Parties as follows:

Section 1.Terms Generally. Unless otherwise defined in this Agreement or in the Credit Agreement, terms defined in Article 8 or 9 of the UCC (as defined below) and/or in the Federal Book Entry Regulations (as defined below) are used in this Agreement as such terms are defined in such Article 8 or 9 and/or the Federal Book Entry Regulations. “UCC” means the Uniform Commercial Code as in effect, from time to time, in the State of New York; provided that, if perfection or the effect of perfection or non-perfection or the priority of any security interest in any Collateral is governed by the Uniform Commercial Code as in effect in a jurisdiction other than the State of New York, “UCC” means the Uniform Commercial Code as in effect from time to time in such other jurisdiction for purposes of the provisions hereof relating to such perfection, effect of perfection or non-perfection or priority. “Federal Book Entry Regulations” means (a) the federal regulations contained in Subpart B (“Treasury/Reserve Automated Debt Entry System (TRADES)”) governing book-entry securities consisting of U.S. Treasury bonds, notes and bills and Subpart D (“Additional Provisions”) of 31 C.F.R.

Part 357, 31 C.F.R. § 357.2, § 357.10 through § 357.14 and § 357.41 through § 357.44 and (b) to the extent substantially identical to the federal regulations referred to in clause (a) above (as in effect from time to time), the federal regulations governing other book-entry securities.

Section 2.Grant of Security. Each Grantor hereby assigns and transfers to the Administrative Agent, and hereby grants to the Administrative Agent, for the ratable benefit of the Secured Parties, a security interest in all of the following property now owned or at any time hereafter acquired by such Grantor or in which such Grantor now has or at any time in the future may acquire any right, title or interest (collectively, the “Collateral”), as collateral security for the prompt and complete payment and performance when due (whether at stated maturity, by acceleration or otherwise) of such Grantor’s Secured Obligations (as defined below):

(a)all Equipment;

(b)all Inventory;

(c)all Accounts, Chattel Paper (including tangible chattel paper and electronic chattel paper), Instruments (including promissory notes), Securities Accounts, General Intangibles (including payment intangibles, Swap Contracts and rights as administrative agent or other agent under any loan agreements relating to Pledged Debt (as defined below)) and all Supporting Obligations (any and all of such Accounts, Chattel Paper, Instruments, General Intangibles and other obligations, to the extent not referred to in clause (g), (h) or (i) below, being the “Receivables”, and any and all such Supporting Obligations, Security Agreements, Mortgages, Liens, Leases, letters of credit and other contracts being the “Related Contracts”);

(d)all As-Extracted Collateral;

(e)all Fixtures;

(f)all Letter-of-Credit Rights;

(g)the following (the “Security Collateral”):

(i)the Initial Pledged Equity and the certificates, if any, representing the Initial Pledged Equity, and all dividends, distributions, return of capital, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of the Initial Pledged Equity and all subscription warrants, rights or options issued thereon or with respect thereto;

(ii)all additional shares of stock and other Equity Interests in Restricted Subsidiaries, from time to time acquired by such Grantor in any manner (such shares and other Equity Interests, together with the Initial Pledged Equity, being the “Pledged Equity”), and the certificates, if any, representing such additional shares or other Equity Interests, and all dividends, distributions, return of capital, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of such shares or other Equity Interests and all subscription warrants, rights or options issued thereon or with respect thereto;

(iii)all Indebtedness from time to time owed to such Grantor (such Indebtedness, the “Pledged Debt”) and the instruments, if any, evidencing such Indebtedness, and all interest, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of such Indebtedness; and

(iv)all other Investment Property (including all (A) Securities, whether Certificated Securities or Uncertificated Securities, (B) Security Entitlements, (C) Securities Accounts, (D) Commodity Contracts and (E) Commodity Accounts) in which such Grantor has now, or acquires from time to time hereafter,

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any right, title or interest in any manner, and the certificates or instruments, if any, representing or evidencing such investment property, and all dividends, distributions, return of capital, interest, distributions, value, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of such investment property and all subscription warrants, rights or options issued thereon or with respect thereto;

(h)all Deposit Accounts;

(i)all rights, priorities and privileges relating to intellectual property, whether arising under United States, multinational or foreign laws or otherwise, including, without limitation, the following (collectively, “Intellectual Property”):

(i)(A) all copyrights arising under the laws of the United States, any other country or any political subdivision thereof, whether registered or unregistered and whether published or unpublished, all registrations and recordings thereof, and all applications in connection therewith, including, without limitation, all registrations, recordings and applications in the United States Copyright Office, (B) the right to obtain all renewals of the foregoing (clauses (A) and (B), collectively, “Copyrights”) and (C) all written agreements naming any Grantor as licensor or licensee, granting any right under any Copyright, including, without limitation, the grant of rights to manufacture, distribute, exploit and sell materials derived from any Copyright;

(ii)(A) all letters patent of the United States, any other country or any political subdivision thereof, all reissues and extensions thereof and all goodwill associated therewith, (B) all applications for letters patent of the United States or any other country and all divisions, continuations and continuations-in-part thereof, (C) all rights to obtain any reissues or extensions of any of the foregoing (clauses (A) through (C), collectively, “Patents”) and (D) all agreements, whether written or oral, providing for the grant by or to any Grantor of any right to manufacture, use or sell any invention covered in whole or in part by a Patent;

(iii)(A) all trademarks, trade names, corporate names, company names, business names, fictitious business names, trade styles, service marks, logos and other source or business identifiers, and all goodwill associated therewith, now existing or hereafter adopted or acquired, all registrations and recordings thereof, and all applications in connection therewith, whether in the United States Patent and Trademark Office or in any similar office or agency of the United States, any State thereof or any other country or any political subdivision thereof, or otherwise, and all common-law rights related thereto, (B) the right to obtain all renewals of any of the foregoing (clauses (A) and (B), collectively, “Trademarks”) and (C) all agreements, whether written or oral, providing for the grant by or to any Grantor of any right to use any Trademark;

(iv)all trade secrets and confidential information;

(v)all tangible and digital embodiments of the foregoing; and

(vi)all rights to sue at law or in equity for any infringement or other impairment thereof, including the right to receive all proceeds and damages therefrom;

(j)all Documents (other than title documents with respect to vessels or vehicles);

(k)all books and records (including customer lists, credit files, printouts and other computer output materials and records) of such Grantor pertaining to any of the Collateral; and

(l)all proceeds of, collateral for, income, royalties and other payments now or hereafter due and payable with respect to, and Supporting Obligations relating to, any and all of the Collateral (including proceeds, collateral and Supporting Obligations that constitute property of the types described in clauses (a) through (k) of this Section 2 and this clause (l)) and, to the extent not otherwise included, all (A) payments under

3

insurance (whether or not the Administrative Agent is the loss payee thereof), or any indemnity, warranty or guaranty, payable by reason of loss or damage to or otherwise with respect to any of the foregoing Collateral, (B) tort claims, including all Commercial Tort Claims and (C) cash and Cash Equivalents;

provided that the following property is excluded from the foregoing security interests: (A) voting Equity Interests in any CFC, to the extent (but only to the extent) required to prevent the Collateral from including more than 66% of all voting Equity Interests in such CFC, (B) Equipment leased by a Grantor under a lease or otherwise financed pursuant to a purchase-money financing arrangement that prohibits the granting of a Lien on such Equipment, (C) any general intangible, investment property or other rights arising under any contract, instrument, license or other document or under any law, regulation, permit, order or decree of any Governmental Authority if (but only to the extent that) the grant of a security interest therein would constitute a violation of a legally effective restriction in respect of such general intangible, investment property or other rights in favor of a third party, unless and until all required consents shall have been obtained (for the avoidance of doubt, the restrictions described herein are not negative pledge or similar undertakings in favor of a lender or other financial counterparty) and (D) to the extent that (and only to the extent that) the grant of a security interest therein would constitute a material violation of applicable Law, any other property (any and all such excluded property being the “Excluded PersonalProperty”). Each Grantor shall, if requested to do so by the Administrative Agent, use commercially reasonable efforts to obtain any such required consent that is reasonably obtainable with respect to Collateral which the Administrative Agent reasonably determines to be material.

Section 3.Security for Obligations. This Agreement secures, in the case of each Grantor, the payment of all Obligations of any Loan Party (all such Obligations being the “Secured Obligations”).

Section 4.Grantors Remain Liable. Anything herein to the contrary notwithstanding:

(a)each Grantor shall remain liable under the contracts and agreements included in such Grantor’s Collateral to the extent set forth therein to perform all of its duties and obligations thereunder to the same extent as if this Agreement had not been executed;

(b)the exercise by the Administrative Agent of any of the rights hereunder shall not release any Grantor from any of its duties or obligations under the contracts and agreements included in the Collateral; and

(c)no Secured Party shall have any obligation or liability under the contracts and agreements included in the Collateral by reason of this Agreement, any other Loan Document or any Lender Contract, nor shall any Secured Party be obligated to perform any of the obligations or duties of any Grantor thereunder or to take any action to collect or enforce any claim for payment assigned hereunder.

Section 5.Delivery and Control of Security Collateral. (1) Subject to Section 5(i) below, all certificates or instruments representing or evidencing Security Collateral shall be delivered to and held by or on behalf of the Administrative Agent pursuant hereto and shall be in suitable form for transfer by delivery, or shall be accompanied by duly executed instruments of transfer or assignment in blank, all in form and substance satisfactory to the Administrative Agent. The Administrative Agent shall have the right, at any time in its discretion and without notice to any Grantor, to transfer to or to register in the name of the Administrative Agent or any of its nominees any or all of the Security Collateral, subject only to the revocable rights specified in Section 11(a). In addition, the Administrative Agent shall have the right, upon the occurrence and during the continuance of an Event of Default at any time to exchange certificates or instruments representing or evidencing Security Collateral for certificates or instruments of smaller or larger denominations.

4

(a)Subject to Section 5(i) below, with respect to any Security Collateral in which any Grantor has any right, title or interest and that constitutes an uncertificated security, such Grantor will cause the issuer thereof either:

(i)to register the Administrative Agent as the registered owner of such security or

(ii)to agree in an authenticated record with such Grantor and the Administrative Agent that such issuer will comply with instructions with respect to such security originated by the Administrative Agent without further consent of such Grantor, such authenticated record to be in form and substance satisfactory to the Administrative Agent.

With respect to any Security Collateral in which any Grantor has any right, title or interest and that is not an uncertificated security, upon the request of the Administrative Agent, such Grantor will notify each such issuer of Pledged Equity that such Pledged Equity is subject to the security interest granted hereunder. Each Grantor that is the issuer of any Security Collateral or Pledged Equity belonging to another Grantor acknowledges the security interest granted hereunder in such Security Collateral and will take the actions described above in this clause (b).

(b)Subject to Section 5(i) below, with respect to any Security Collateral in which any Grantor has any right, title or interest and that constitutes a security entitlement in which the Administrative Agent is not the entitlement holder, such Grantor will cause the securities intermediary with respect to such security entitlement either:

(i)to identify in its records the Administrative Agent as the entitlement holder of such security entitlement against such securities intermediary or

(ii)to agree in an authenticated record with such Grantor and the Administrative Agent that such securities intermediary will comply with entitlement orders (that is, notifications communicated to such securities intermediary directing transfer or redemption of the financial asset to which such Grantor has a security entitlement) originated by the Administrative Agent without further consent of such Grantor, such authenticated record to be in form and substance satisfactory to the Administrative Agent (such agreements together being the “Securities Account Control Agreements”).

(c)Subject to Section 5(i) below, no Grantor will add any securities intermediary that maintains a Securities Account for such Grantor or open any new securities account with any then-existing securities intermediary unless:

(i)the Administrative Agent shall have received at least 10 days’ prior written notice of such securities intermediary or such new Securities Account, and

(ii)the Administrative Agent shall have received, in the case of a securities intermediary that is not the Administrative Agent, a Securities Account Control Agreement authenticated by such new securities intermediary and such Grantor, or a supplement to an existing Securities Account Control Agreement with such then-existing securities intermediary, covering such new Securities Account.

No Grantor shall terminate any securities intermediary or terminate any Securities Account, except that a Grantor may terminate a Securities Account, and terminate a securities intermediary with respect to such Securities Account if it gives the Administrative Agent at least 10 days’ prior written notice of such termination.

(d)Subject to Section 5(i) below, upon any termination by a Grantor of any Securities Account or any securities intermediary with respect thereto, such Grantor will immediately:

5

(i)transfer all property held in such terminated Securities Account to another Securities Account, and

(ii)notify all Obligors that were making payments to such Securities Account to make all future payments to another Securities Account, in each case so that the Administrative Agent shall have a continuously perfected security interest in such funds and property.

(e)So long as no Event of Default shall have occurred and be continuing, each Grantor shall have sole right to direct the disposition of funds with respect to each of its Securities Accounts.

(f)The Administrative Agent may transfer, direct the transfer of, or sell property credited to any Securities Account to satisfy the Grantor’s obligations under the Loan Documents and the Lender Contracts if an Event of Default shall have occurred and be continuing.

(g)Upon the request of the Administrative Agent upon the occurrence and during the continuance of an Event of Default, such Grantor will notify each such issuer of Pledged Debt that such Pledged Debt is subject to the security interest granted hereunder.

(h)Clauses (a) through (e) above shall not be applicable to any Collateral except Pledged Equity constituting certificated securities prior to the occurrence of an Event of Default.

Section 6.Maintaining Deposit, Securities and Commodity Accounts. Only upon the occurrence and during the continuance of an Event of Default,

(a)Each Grantor will maintain all Deposit Accounts, Securities Accounts and Commodity Accounts only with the Administrative Agent or with banks (the “Pledged Account Banks”) that have agreed, in a record authenticated by the Grantor, the Administrative Agent and the Pledged Account Banks, to:

(i)comply with instructions originated by the Administrative Agent directing the disposition of funds in the Deposit Accounts, Securities Accounts and Commodity Accounts without the further consent of the Grantor, and

(ii)waive or subordinate in favor of the Administrative Agent all claims of the Pledged Account Banks (including claims by way of a security interest, lien or right of setoff or right of recoupment) to the Deposit Accounts, Securities Accounts and Commodity Accounts, which authenticated record shall be in form and substance reasonably satisfactory to, and as negotiated in good faith by, the Administrative Agent (such agreements together being the “Account Control Agreements”), provided that each Grantor shall promptly (but in any case within 45 days) provide any such Account Control Agreement following the occurrence of an Event of Default (as defined in the Credit Agreement).

(b)Each Grantor will promptly instruct each Person obligated at any time to make any payment to such Grantor for any reason (an “Obligor”) to make such payment to a Deposit Account.

(c)Except for any Deposit Account holding Cash Collateral, no Grantor will add any bank that maintains a Deposit Account for such Grantor or open any new deposit account with any then-existing Pledged Account Bank unless:

(i)the Administrative Agent shall have received at least 10 days’ prior written notice of such additional bank or such new Deposit Account, and

(ii)the Administrative Agent shall have received, in the case of a bank or Pledged Account Bank that is not the Administrative Agent, an Account Control Agreement authenticated by such new

6

bank and such Grantor, or a supplement to an existing Account Control Agreement with such then existing Pledged Account Bank, covering such new Deposit Account.

No Grantor shall terminate any bank as a Pledged Account Bank or terminate any Deposit Accounts or Securities Accounts, except that a Grantor may terminate a Deposit Account, and terminate a bank as a Pledged Account Bank with respect to such Deposit Account if it gives the Administrative Agent at least 10 days’ prior written notice of such termination.

(d)Upon any termination by a Grantor of any Deposit Account or any Pledged Account Bank with respect thereto, such Grantor will immediately:

(i)transfer all funds held in such terminated Deposit Account to another Deposit Account, and

(ii)notify all Obligors that were making payments to such Deposit Account to make all future payments to another Deposit Account, in each case so that the Administrative Agent shall have a continuously perfected security interest in such funds and property.

(e)So long as no Event of Default shall have occurred and be continuing, each Grantor shall have sole right to direct the disposition of funds with respect to each of its Deposit Accounts.

(f)The Administrative Agent may, at any time and without notice to, or consent from, a Grantor transfer, or direct the transfer of, funds from the Deposit Accounts and Securities Accounts to satisfy the Grantor’s obligations under the Loan Documents and Lender Contracts if an Event of Default shall have occurred and be continuing.

(g)Upon the occurrence and during the continuance of any Event of Default, the Administrative Agent shall be authorized to send to each Pledged Account Bank a Notice of Exclusive Control as defined in and under any Account Control Agreement.

Section 7.Representations and Warranties. Each Grantor represents and warrants as follows:

(a)As of the Closing Date, such Grantor’s exact legal name, as defined in Section 9-503(a) of the UCC, is correctly set forth in Schedule I (as amended as provided in Section 11(a)). As of the Closing Date, such Grantor is located (within the meaning of Section 9-307 of the UCC), is the type of organization and is organized in the state or jurisdiction set forth in Schedule I (as amended as provided in Section 9(a)). As of the Closing Date, the information set forth in Schedule I (as amended as provided in Section 9(a)) with respect to such Grantor is true and accurate in all respects. As of the Closing Date, such Grantor has not, within the prior five years, changed its name, location, chief executive office, place where it maintains its agreements, type of organization, jurisdiction of organization or organizational identification number from those set forth in Schedule I (as amended as provided in Section 9(a)) except as disclosed in Schedule I.

(b)To the extent required by the terms hereof, all Security Collateral consisting of certificated securities has been delivered into the control of the Administrative Agent.

(c)Such Grantor is the legal and beneficial owner of the Collateral of such Grantor free and clear of any Lien, claim, option or right of others, except for the security interest created under this Agreement or as permitted under the Credit Agreement. No effective financing statement or other instrument similar in effect covering all or any part of such Collateral or listing such Grantor or any trade name of such Grantor as debtor is on file in any recording office, except such as may have been filed in favor of the Administrative Agent relating to the Loan Documents or as otherwise permitted under the Credit Agreement.

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(d)With respect to the Pledged Equity that is an uncertificated security, such Grantor has caused, to the extent required by the terms hereof, the issuer thereof either:

(i)to register the Administrative Agent as the registered owner of such security or

(ii)to agree in an authenticated record with such Grantor and the Administrative Agent that such issuer will comply with instructions with respect to such security originated by the Administrative Agent without further consent of such Grantor.

If such Grantor is an issuer of Pledged Equity, such Grantor confirms that it has received notice of such security interest.

(e)The Initial Pledged Equity pledged by such Grantor constitutes the percentage of the issued and outstanding Equity of the issuers thereof indicated on Schedule II.

(f)(i) To the extent required by the terms hereof, all filings and other actions (including (A) actions necessary to obtain control of Collateral as provided in Sections 9-104, 9-105, 9-106 and 9-107 of the UCC and (B) actions necessary to perfect the Administrative Agent’s security interest with respect to Collateral evidenced by a certificate of ownership) necessary to perfect the security interest in the Collateral of such Grantor created under this Agreement have been duly made or taken and are in full force and effect, and (ii) this Agreement creates in favor of the Administrative Agent for the benefit of the Secured Parties a valid and, together with such filings and other actions, perfected first priority security interest in the Collateral of such Grantor (subject to Permitted Liens), securing the payment of the Secured Obligations except as otherwise expressly contemplated hereby.

Section 8.Further Assurances. (1) From time to time, at the expense of such Grantor, each Grantor will promptly execute and deliver, or otherwise authenticate, all further instruments and documents, and take all further action that may be necessary or desirable, or that the Administrative Agent may reasonably request, in order to perfect and protect any pledge or security interest granted or purported to be granted by such Grantor hereunder or to enable the Administrative Agent to exercise and enforce its rights and remedies hereunder with respect to any Collateral of such Grantor. Without limiting the generality of the foregoing, each Grantor will promptly with respect to Collateral of such Grantor:

(i)upon the occurrence and during the continuance of an Event of Default, mark conspicuously each document included in Inventory, each Chattel Paper included in Receivables, each Related Contract, and, at the reasonable request of the Administrative Agent, each of its records pertaining to such Collateral with a legend, in form and substance satisfactory to the Administrative Agent, indicating that such document, Chattel Paper, Related Contract or Collateral is subject to the security interest granted hereby;

(ii)execute or authenticate and file such financing or continuation statements, or amendments thereto, and such other instruments or notices, as may be necessary or desirable, or as the Administrative Agent may request, in order to perfect and preserve the security interest granted or purported to be granted by such Grantor hereunder;

(iii)[reserved];

(iv)Upon the occurrence and during the continuance of an Event of Default, upon the acquisition of any electronic Chattel Paper, investment property, letter-of-credit rights and transferable records as provided in Sections 9-104, 9-105, 9-106 and 9-107 of the UCC by any Grantor, the Borrower shall promptly notify the Administrative Agent of such acquisition, and upon the reasonable request of the Administrative Agent, the Borrower shall promptly take all action necessary to ensure that the Administrative Agent has control of such

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Collateral consisting of electronic Chattel Paper, investment property, letter-of-credit rights and transferable records as provided in Sections 9-105, 9-106 and 9-107 of the UCC;

(v)upon the occurrence and during the continuance of an Event of Default, at the reasonable request of the Administrative Agent, take all action to ensure that the Administrative Agent’s security interest is noted on any certificate of ownership related to any Collateral evidenced by a certificate of ownership; and

(vi)deliver to the Administrative Agent evidence that all other action that the Administrative Agent may deem reasonably necessary or desirable in order to perfect and protect the security interest created by such Grantor under this Agreement has been taken.

(b)Each Grantor authorizes the Administrative Agent to file one or more financing or continuation statements, and amendments thereto, including one or more financing statements indicating that such financing statements cover all assets or all personal property (or words of similar effect) of such Grantor, in each case without the signature of such Grantor, and regardless of whether any particular asset described in such financing statements falls within the scope of the UCC or the granting clause of this Agreement. A photocopy or other reproduction of this Agreement or any financing statement covering the Collateral or any part thereof shall be sufficient as a financing statement where permitted by law. Each Grantor ratifies its authorization for the Administrative Agent to have filed such financing statements, continuation statements or amendments filed prior to the date hereof.

(c)Each Grantor will furnish to the Administrative Agent from time to time statements and schedules further identifying and describing the Collateral of such Grantor and such other reports in connection with such Collateral as the Administrative Agent may reasonably request, all in reasonable detail.

Section 9.Collections on Receivables and Related Contracts. Except as otherwise provided in this Section 9, each Grantor will continue to collect, at its own expense, all amounts due or to become due to such Grantor under Receivables and Related Contracts. In connection with such collections, such Grantor may take such action as such Grantor may deem necessary or advisable to enforce collection of the Receivables and Related Contracts; provided that the Administrative Agent shall have the right at any time, upon the occurrence and during the continuance of an Event of Default and upon written notice to such Grantor of its intention to do so, to notify the Obligors under any Receivables and Related Contracts of the assignment of such Receivables and Related Contracts to the Administrative Agent and to direct such Obligors to make payment of all amounts due or to become due to such Grantor thereunder directly to the Administrative Agent and, upon such notification and at the expense of such Grantor, to enforce collection of any such Receivables and Related Contracts, to adjust, settle or compromise the amount or payment thereof, in the same manner and to the same extent as such Grantor might have done, and to otherwise exercise all rights with respect to such Receivables and Related Contracts, including those set forth set forth in Section 9-607 of the UCC.

Section 10.As to Intellectual Property. (a) With respect to its Intellectual Property, each Grantor will execute or otherwise authenticate an Intellectual Property security agreement, in form and substance satisfactory to the Administrative Agent, for recording the security interest granted hereunder to the Administrative Agent in such Intellectual Property, material to the operations of such Grantor, with the U.S. Patent and Trademark Office, the U.S. Copyright Office and any other governmental authorities necessary to perfect the security interest hereunder in such Intellectual Property, provided however that such recording of security interest with the U.S. Patent and Trademark Office and/or U.S. Copyright Office shall only cover United States federal registered Patents, Copyrights or Trademarks, as applicable.

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(a)Should any Grantor obtain an ownership interest in any item of the type set forth in Section 2(i) that is not on the date hereof a part of the Intellectual Property:

(i)this Agreement shall automatically apply thereto, and

(ii)any such item and, in the case of Trademarks, the goodwill symbolized thereby, shall automatically become part of the Intellectual Property subject to this Agreement.

(b)This Section shall only be applicable upon the occurrence and during the continuance of an Event of Default.

Each Grantor shall give prompt written notice to the Administrative Agent identifying such items, and such Grantor shall execute and deliver to the Administrative Agent with such written notice, or otherwise authenticate, an intellectual property security agreement supplement in form and substance satisfactory to the Administrative Agent covering such items, which supplement shall be recorded with the U.S. Patent and Trademark Office, the U.S. Copyright Office and any other governmental authorities necessary to perfect the security interest hereunder in such items.

Section 11.Voting Rights; Dividends; Etc. (1) Except as set forth in clause (b):

(i)Each Grantor shall be entitled to exercise any and all voting and other consensual rights pertaining to the Security Collateral owned by such Grantor or any part thereof for any purpose; provided that such Grantor will not exercise or refrain from exercising any such right if such action would have a material adverse effect on the value of the Security Collateral.

(ii)Each Grantor shall be entitled to receive and retain any and all dividends, interest and other distributions paid in respect of the Security Collateral owned by such Grantor if and to the extent that the payment thereof is not otherwise prohibited by the terms of the Loan Documents.

(iii)The Administrative Agent will execute and deliver (or cause to be executed and delivered) to each Grantor all such proxies and other instruments as such Grantor may reasonably request for the purpose of enabling such Grantor to exercise the voting and other rights that it is entitled to exercise pursuant to clause (i) above and to receive the dividends or interest payments that it is authorized to receive and retain pursuant to clause (ii) above.

(b)Upon the occurrence and during the continuance of an Event of Default that has not been waived:

(i)All rights of each Grantor:

(A)to exercise or refrain from exercising the voting and other consensual rights that it would otherwise be entitled to exercise pursuant to Section 11(a)(i) shall, upon notice to such Grantor by the Administrative Agent, cease and

(B)to receive the dividends, interest and other distributions that it would otherwise be authorized to receive and retain pursuant to Section 11(a)(ii) shall automatically cease,

and all such rights shall thereupon become vested in the Administrative Agent, which shall thereupon have the sole right to exercise or refrain from exercising such voting and other consensual rights and to receive and hold as Security Collateral such dividends, interest and other distributions.

(ii)All dividends, interest and other distributions that are received by any Grantor contrary to the provisions of clause (i) of this Section 11(b) shall be received in trust for the benefit of the

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Administrative Agent, shall be segregated from other funds of such Grantor and shall be forthwith paid over to the Administrative Agent as Security Collateral in the same form as so received (with any necessary indorsement).

(iii)The Administrative Agent shall be authorized to send to each Securities Intermediary as defined in and under any Securities Account Control Agreement a Notice of Exclusive Control as defined in and under such Securities Account Control Agreement.

Section 12.Additional Shares. Each Grantor will pledge hereunder, immediately upon its acquisition (directly or indirectly) thereof, any additional Equity Interests or other securities of each issuer of the Pledged Equity to the extent constituting Collateral.

Section 13.Administrative Agent Appointed Attorney-in-Fact. Each Grantor irrevocably appoints the Administrative Agent such Grantor’s attorney-in-fact, with full authority in the place and stead of such Grantor and in the name of such Grantor or otherwise, from time to time, upon the occurrence and during the continuance of an Event of Default, in the Administrative Agent’s discretion, to take any action and to execute any instrument that the Administrative Agent may deem necessary or advisable to accomplish the purposes of this Agreement, including, without limitation:

(a)to obtain and adjust insurance required to be paid to the Administrative Agent pursuant to Section 6.07 of the Credit Agreement.

(b)to ask for, demand, collect, sue for, recover, compromise, receive and give acquittance and receipts for moneys due and to become due under or in respect of any of the Collateral,

(c)to receive, indorse and collect any drafts or other instruments, documents and Chattel Paper, in connection with clause (a) or (b) above, and

(d)to file any claims or take any action or institute any proceedings that the Administrative Agent may deem necessary or desirable for the collection of any of the Collateral or otherwise to enforce the rights of the Administrative Agent with respect to any of the Collateral.

Section 14.Administrative Agent May Perform. If any Grantor fails to perform any agreement contained herein, the Administrative Agent may, but without any obligation to do so and without notice, itself perform, or cause performance of, such agreement, and the expenses of the Administrative Agent incurred in connection therewith shall be payable by such Grantor under Section 17.

Section 15.The Administrative Agent’s Duties. (a) The powers conferred on the Administrative Agent hereunder are solely to protect the Secured Parties’ interest in the Collateral and shall not impose any duty upon it to exercise any such powers. Except for the safe custody of any Collateral in its possession and the accounting for moneys actually received by it hereunder, the Administrative Agent shall have no duty as to any Collateral, as to ascertaining or taking action with respect to calls, conversions, exchanges, maturities, tenders or other matters relative to any Collateral, whether or not any Secured Party has or is deemed to have knowledge of such matters, or as to the taking of any necessary steps to preserve rights against any parties or any other rights pertaining to any Collateral. The Administrative Agent shall be deemed to have exercised reasonable care in the custody and preservation of any Collateral in its possession if such Collateral is accorded treatment substantially equal to that which it accords its own property.

(a)Anything contained herein to the contrary notwithstanding, the Administrative Agent may from time to time, when the Administrative Agent deems it to be necessary, appoint one or more subagents for the Administrative Agent hereunder with respect to all or any part of the Collateral. If the Administrative Agent so appoints any such subagent with respect to any Collateral:

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(i)the assignment and pledge of such Collateral and the security interest granted in such Collateral by each Grantor hereunder shall be deemed for purposes of this Security Agreement to have been made to such subagent, in addition to the Administrative Agent, for the ratable benefit of the Secured Parties, as security for the Secured Obligations of such Grantor,

(ii)such subagent shall automatically be vested, in addition to the Administrative Agent, with all rights, powers, privileges, interests and remedies of the Administrative Agent hereunder with respect to such Collateral, and

(iii)the term “Administrative Agent,” when used herein in relation to any rights, powers, privileges, interests and remedies of the Administrative Agent with respect to such Collateral, shall include such subagent;

provided that no such subagent shall be authorized to take any action with respect to any such Collateral unless and except to the extent expressly authorized in writing by the Administrative Agent.

Section 16.Remedies. If any Event of Default shall have occurred and be continuing:

(a)The Administrative Agent may exercise in respect of the Collateral, in addition to other rights and remedies provided for herein or otherwise available to it, all the rights and remedies of a Secured Party upon default under the UCC (whether or not the UCC applies to the affected Collateral) and also may:

(i)require each Grantor to, and each Grantor will at its expense and upon request of the Administrative Agent forthwith, assemble all or part of the Collateral as directed by the Administrative Agent and make it available to the Administrative Agent at a place and time to be designated by the Administrative Agent that is reasonably convenient to both parties;

(ii)without notice except as specified below, sell the Collateral or any part thereof in one or more parcels at public or private sale, at any of the Administrative Agent’s offices or elsewhere, for cash, on credit or for future delivery, and upon such other terms as the Administrative Agent may deem commercially reasonable;

(iii)occupy any premises owned or leased by any of the Grantors where the Collateral or any part thereof is assembled or located for a reasonable period in order to effectuate its rights and remedies hereunder or under law, without obligation to such Grantor in respect of such occupation; and

(iv)exercise any and all rights and remedies of any of the Grantors under or in connection with the Collateral, or otherwise in respect of the Collateral, including:

(A)any and all rights of such Grantor to demand or otherwise require payment of any amount under, or performance of any provision of, the Receivables, the Related Contracts and the other Collateral,

(B)withdraw, or cause or direct the withdrawal, of all funds with respect to the Deposit Accounts or Securities Accounts, and

(C)exercise all other rights and remedies with respect to the Receivables, the Related Contracts and the other Collateral, including those set forth in Section 9-607 of the UCC.

To the extent that notice of sale shall be required by law, at least 10 days’ notice to such Grantor of the time and place of any public sale or the time after which any private sale is to be made shall constitute reasonable notification. The Administrative Agent shall not be obligated to make any sale of Collateral regardless of notice

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of sale having been given. The Administrative Agent may adjourn any public or private sale from time to time by announcement at the time and place fixed therefor, and such sale may, without further notice, be made at the time and place to which it was so adjourned.

(b)Any cash held by or on behalf of the Administrative Agent and all cash proceeds received by or on behalf of the Administrative Agent in respect of any sale of, collection from, or other realization upon all or any part of the Collateral may, in the discretion of the Administrative Agent, be held by the Administrative Agent as collateral for, and/or then or at any time thereafter applied (after payment of any amounts payable to the Administrative Agent pursuant to Section 17) in whole or in part by the Administrative Agent for the ratable benefit of the Secured Parties against, all or any part of the Secured Obligations, in accordance with Section 8.03 of the Credit Agreement.

(c)The Administrative Agent may, without notice to any Grantor, except as required by law and at any time or from time to time, charge, set-off and otherwise apply all or any part of the Secured Obligations against any funds held with respect to the Deposit Accounts and Securities Accounts or in any other deposit account or securities account.

(d)In the event of any sale or other disposition of any of the Intellectual Property of any Grantor, the goodwill symbolized by any trademarks subject to such sale or other disposition shall be included therein, and such Grantor shall supply to the Administrative Agent or its designee such Grantor’s know-how and expertise, and documents and things relating to any Intellectual Property subject to such sale or other disposition, and such Grantor’s customer lists and other records and documents relating to such Intellectual Property and to the manufacture, distribution, advertising and sale of products and services of such Grantor.

(e)The Grantors recognize that the Administrative Agent may deem it impracticable to effect a public sale of all or any part of the Security Collateral and that the Administrative Agent may, therefore, determine to make one or more private sales of any such securities to a restricted group of purchasers who will be obligated to agree, among other things, to acquire such securities for their own account, for investment and not with a view to the distribution or resale thereof. The Grantors acknowledge that any such private sale may be at prices and on terms less favorable to the seller than the prices and other terms which might have been obtained at a public sale and, notwithstanding the foregoing, agree that such private sales shall be deemed to have been made in a commercially reasonable manner and that the Administrative Agent shall have no obligation to delay sale of any such securities for the period of time necessary to permit the Issuer of such securities to register such securities for public sale under the Securities Act of 1933, as amended. Any offer to sell such securities that has been:

(i)publicly advertised on a bona fide basis in a newspaper or other publication of general circulation in the financial community of New York, New York (to the extent that such an offer may be so advertised without prior registration under such Securities Act), or

(ii)made privately in the manner described above to not less than 15 bona- fide offerees, shall be deemed to involve a “public disposition” for the purposes of Section 9‑610(c) of the UCC (or any successor or similar, applicable statutory provision), notwithstanding that such sale may not constitute a “public offering” under the Securities Act, and that the Administrative Agent or any other Secured Party may, in such event, bid for the purchase of such securities.

Section 17.Subordination of Liens. Each Grantor confirms that: (a) any and all Liens securing debts, liabilities and other Obligations owed to such Grantor by any other Loan Party (“Subordinated Liens”) shall be subordinate to any and all Liens under the Security Documents securing the Secured Obligations (“Senior

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Liens”) as if the Senior Liens were created, filed, recorded and otherwise perfected prior in time to the creation, filing, recording and other perfection of the Subordinated Liens, and

(a)by reason of this Agreement, the Administrative Agent, for the benefit of the Secured Parties, has a perfected, first-priority Lien on each Subordinated Lien and the right, to the exclusion of any Grantor, to enforce, exercise remedies, grant waivers, release and take any and all other actions with respect to such Subordinated Lien.

Section 18.Amendments; Waivers; Additional Grantors; Etc. (a) No amendment or waiver of any provision of this Agreement, and no consent to any departure by any Grantor here from shall in any event be effective unless the same shall be entered into in accordance with Section 10.01 of the Credit Agreement. No failure on the part of the Administrative Agent or any other Secured Party to exercise, and no delay in exercising any right hereunder, shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right.

(a)Upon the execution and delivery, or authentication, by any Person of a security agreement supplement in substantially the form of Exhibit A hereto (each a “Security Agreement Supplement”):

(i)such Person shall be referred to as an “Additional Grantor” and shall be and become a Grantor hereunder, and each reference in this Agreement and the other Loan Documents to “Grantor” shall also mean and be a reference to such Additional Grantor, and each reference in this Agreement, the other Loan Documents and the Lender Contracts to “Collateral” shall also mean and be a reference to the Collateral of such Additional Grantor, and

(ii)the supplemental schedules attached to each Security Agreement Supplement shall be incorporated into and become a part of and supplement the respective Schedule hereto, and the Administrative Agent may attach such supplemental schedules to such Schedules; and each reference to such Schedules shall mean and be a reference to such Schedules as supplemented pursuant to each Security Agreement Supplement.

Section 19.Notices, Etc. All notices and other communications provided for hereunder shall be delivered in the manner provided in the Credit Agreement, in the case of the Borrower or the Administrative Agent, addressed to it at its address specified in the Credit Agreement and, in the case of each Grantor other than the Borrower, addressed to it at its address set forth opposite such Grantor’s name on the signature pages hereto or on the signature page to the Security Agreement Supplement pursuant to which it became a party hereto; or, as to any party, at such other address as shall be designated by such party in a written notice to the other parties. All such notices and other communications shall be effective when and as provided in the Credit Agreement. Delivery by telecopier of an executed counterpart of any amendment or waiver of any provision of this Agreement or of any Security Agreement Supplement or Schedule hereto shall be effective as delivery of an original executed counterpart thereof.

Section 20.Continuing Security Interest; Assignments under the Credit Agreement. This Agreement shall create a continuing security interest in the Collateral and shall:

(a)remain in full force and effect until the latest of:

(i)the payment in full of all Secured Obligations,

(ii)the termination or expiration of all Commitments and

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(iii)the termination or expiration of all Letters of Credit and all Lender Contracts with a Lender Counterparty,

(b)be binding upon each Grantor, its successors and assigns and

(c)inure, together with the rights and remedies of the Administrative Agent hereunder, to the benefit of the Secured Parties and their respective successors, transferees and assigns.

Without limiting the generality of the foregoing clause (c), any Secured Party may assign or otherwise transfer all or any portion of its rights and obligations under the Credit Agreement (including all or any portion of its Commitment, the Loans owing to it and the Note or Notes, if any, held by it), to any other Person, and such other Person shall thereupon become vested with all the benefits in respect thereof granted to such Secured Party herein or otherwise, in each case as provided in the Credit Agreement.

Section 21.Release; Termination. (a) Upon any sale, lease, transfer or other disposition of any item of Collateral of any Grantor or release of any Guaranty by a Grantor, in each case in accordance with the terms of the Loan Documents (other than sales of Inventory in the ordinary course of business), the Administrative Agent will, at such Grantor’s expense, execute and deliver to such Grantor such documents as such Grantor shall reasonably request to evidence the release of such item of Collateral from the assignment and security interest granted hereby; provided that:

(i)at the time of such request and such release no Event of Default shall have occurred and be continuing,

(ii)such Grantor shall have delivered to the Administrative Agent, at least 10 Business Days prior to the date of the proposed release, a written request for release describing the item of Collateral and the terms of the sale, lease, transfer or other disposition in reasonable detail, including the price thereof and any expenses in connection therewith, together with a form of release for execution by the Administrative Agent and a certificate of such Grantor to the effect that the transaction is in compliance with the Loan Documents and as to such other matters as the Administrative Agent may request and

(iii)the proceeds of any such sale, lease, transfer or other disposition required to be applied, or any payment to be made in connection therewith, in accordance with the Credit Agreement shall, to the extent so required, be paid or made to, or in accordance with the instructions of, the Administrative Agent when and as required under the Credit Agreement.

(b)Upon the payment in full of all Secured Obligations, the termination or expiration of all Commitments and the termination or expiration of all Letters of Credit and all Lender Contracts, the security interest hereunder shall terminate and all rights to the Collateral shall revert to the Grantors.

(c)Upon any termination of the security interests and/or release of Collateral as provided in this Section 21, the Administrative Agent will, at the expense of the applicable Grantor, execute and deliver to such Grantor such documents as it shall reasonably request to evidence the termination of such security interests or the release of such Collateral, as the case may be.

Section 22.Terms Generally; References and Titles. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation.” Unless the context requires otherwise:

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(a)any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein);

(b)any reference herein to any Person shall be construed to include such Person’s successors and assigns;

(c)the words “herein,” “hereof” and “hereunder,” and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof;

(d)all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement;

(e)any reference to any law or regulation herein shall, unless otherwise specified, refer to such law or regulation as amended, modified or supplemented from time to time; and

(f)the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

References to any document, instrument, or agreement shall include:

(i)all exhibits, schedules, and other attachments thereto, and

(ii)shall include all documents, instruments, or agreements issued or executed in replacement thereof.

Titles appearing at the beginning of any subdivision are for convenience only and do not constitute any part of such subdivision and shall be disregarded in construing the language contained in such subdivisions. The phrases “this section”, “this clause” and “this subsection” and similar phrases refer only to the sections, clauses or subsections hereof in which such phrases occur. The word “or” is not exclusive. Accounting terms have the meanings assigned to them by GAAP, as applied by the accounting entity to which they refer. References to “days” shall mean calendar days, unless the term “Business Day” is used. Unless otherwise specified, references herein to any particular Person also refer to its successors and permitted assigns.

Section 23.Execution in Counterparts. This Agreement may be executed in any number of counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Delivery of an executed counterpart of a signature page to this Agreement by telecopier shall be effective as delivery of an original executed counterpart of this Agreement.

Section 24.Governing Law; Jurisdiction; Waiver of Jury Trial, Etc.

(a)THIS AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

(b)EACH GRANTOR IRREVOCABLY AND UNCONDITIONALLY SUBMITS, FOR ITSELF AND ITS PROPERTY, TO THE EXCLUSIVE JURISDICTION OF THE COURTS OF THE STATE OF NEW YORK SITTING IN NEW YORK COUNTY AND OF THE UNITED STATES DISTRICT COURT OF THE SOUTHERN DISTRICT OF NEW YORK, AND ANY APPELLATE COURT FROM ANY THEREOF, IN ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR FOR RECOGNITION OR ENFORCEMENT OF ANY

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JUDGMENT, AND EACH GRANTOR IRREVOCABLY AND UNCONDITIONALLY AGREES THAT ALL CLAIMS IN RESPECT OF ANY SUCH ACTION OR PROCEEDING SHALL BE HEARD AND DETERMINED IN SUCH NEW YORK STATE COURT OR, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, IN SUCH FEDERAL COURT. EACH GRANTOR AGREES THAT A FINAL JUDGMENT IN ANY SUCH ACTION OR PROCEEDING SHALL BE CONCLUSIVE AND MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW. NOTHING IN THIS AGREEMENT SHALL AFFECT ANY RIGHT THAT ANY SECURED PARTY MAY OTHERWISE HAVE TO BRING ANY ACTION OR PROCEEDING RELATING TO THIS AGREEMENT AGAINST ANY GRANTOR OR ITS PROPERTIES IN THE COURTS OF ANY JURISDICTION.

(c)EACH GRANTOR IRREVOCABLY AND UNCONDITIONALLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT IN ANY COURT REFERRED TO IN CLAUSE (b) ABOVE. EACH GRANTOR IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE DEFENSE OF AN INCONVENIENT FORUM TO THE MAINTENANCE OF SUCH ACTION OR PROCEEDING IN ANY SUCH COURT.

(d)EACH GRANTOR IRREVOCABLY CONSENTS TO SERVICE OF PROCESS IN THE MANNER PROVIDED FOR NOTICES IN SECTION 19. NOTHING IN THIS AGREEMENT WILL AFFECT THE RIGHT OF ANY PARTY HERETO TO SERVE PROCESS IN ANY OTHER MANNER PERMITTED BY APPLICABLE LAW.

(e)EACH GRANTOR IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, (I) ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN ANY LEGAL PROCEEDING DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY, AND (II) ANY RIGHT IT MAY HAVE TO CLAIM OR RECOVER IN ANY SUCH LEGAL PROCEEDING ANY “SPECIAL DAMAGES,” AS DEFINED BELOW. EACH GRANTOR (X) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (Y) ACKNOWLEDGES THAT THE OTHER PARTIES TO THE LOAN DOCUMENTS, TREASURY MANAGEMENT SERVICES AGREEMENTS WITH LENDER COUNTERPARTIES AND SWAP CONTRACTS WITH LENDER COUNTERPARTIES HAVE BEEN INDUCED TO ENTER THEREIN BY, AMONG OTHER THINGS, THE WAIVERS AND CERTIFICATIONS IN THIS SECTION. AS USED IN THIS SECTION, “SPECIAL DAMAGES” INCLUDES ALL SPECIAL, CONSEQUENTIAL, EXEMPLARY, OR PUNITIVE DAMAGES (REGARDLESS OF HOW NAMED), BUT DOES NOT INCLUDE ANY PAYMENTS OR FUNDS WHICH ANY PARTY HAS EXPRESSLY PROMISED TO PAY OR DELIVER TO ANY OTHER PARTY.

[SIGNATURES BEGIN NEXT PAGE]

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IN WITNESS WHEREOF, each Grantor has caused this Agreement to be duly executed and delivered by its officer thereunto duly authorized as of the date first above written.

SANDRIDGE ENERGY, INC.

By:    /s/ Julian Bott
Name:    Julian Bott
Title:    Executive Vice President and Chief     Financial Officer

SANDRIDGE HOLDINGS, INC.

By:    /s/ Julian Bott
Name:    Julian Bott
Title:    Executive Vice President and Chief     Financial Officer

SANDRIDGE EXPLORATION AND PRODUCTION, LLC

By:    /s/ Julian Bott
Name:    Julian Bott
Title:    Executive Vice President and Chief     Financial Officer

SANDRIDGE MIDSTREAM INC.

By:    /s/ Julian Bott
Name:    Julian Bott
Title:    Executive Vice President and Chief     Financial Officer

SANDRIDGE OPERATING COMPANY

By:    /s/ Julian Bott
Name:    Julian Bott
Title:    Executive Vice President and Chief     Financial Officer

LARIAT SERVICES, INC.

Signature Page
Security Agreement

By:    /s/ Julian Bott
Name:    Julian Bott
Title:    Executive Vice President and Chief     Financial Officer

INTEGRA ENERGY, L.L.C.

By:    /s/ Julian Bott
Name:    Julian Bott
Title:    Executive Vice President and Chief     Financial Officer

Signature Page
Security Agreement

ROYAL BANK OF CANADA,as Administrative

By:    /s/ Susan Khokher
Name:    Susan Khokher    
Title:    Manager, Agency

Signature Page
Security Agreement

LOCATION, TYPE OF ORGANIZATION, JURISDICTION OF ORGANIZATION AND ORGANIZATIONAL IDENTIFICATION NUMBER

Grantor	Location	Type of Organization	Jurisdiction of Organization	Organizational I.D. No.
SandRidge Energy, Inc.	123 Robert S. Kerr Avenue, Oklahoma City, OK 73102	Corporation	Delaware	20-8084793
SandRidge Operating Company	123 Robert S. Kerr Avenue, Oklahoma City, OK 73102	Corporation	Texas	75-2541245
Integra Energy, L.L.C.	123 Robert S. Kerr Avenue, Oklahoma City, OK 73102	Limited Liability Company	Texas	75-2887527
SandRidge Holdings, Inc.	123 Robert S. Kerr Avenue, Oklahoma City, OK 73102	Corporation	Delaware	20-5878401
SandRidge Exploration and Production, LLC	123 Robert S. Kerr Avenue, Oklahoma City, OK 73102	Limited Liability Company	Delaware	87-0776535
SandRidge Midstream, Inc.	123 Robert S. Kerr Avenue, Oklahoma City, OK 73102	Corporation	Texas	75-2541148
Lariat Services, Inc.	123 Robert S. Kerr Avenue, Oklahoma City, OK 73102	Corporation	Texas	75-2887527

CHANGES IN NAME, LOCATION, CHIEF EXECUTIVE OFFICE, PLACE WHERE IT MAINTAINS AGREEMENTS, TYPE OF ORGANIZATION, JURISDICTION OR ORGANIZATIONAL IDENTIFICATION NUMBER IN LAST FIVE YEARS

Grantor	Changes
SandRidge Energy, Inc.	None
SandRidge Operating Company	None
Integra Energy, L.L.C.	None
SandRidge Holdings, Inc.	None
SandRidge Exploration and Production, LLC	None
SandRidge Midstream, Inc.	None
Lariat Services, Inc.	None

Schedule I

Schedule II to the Security Agreement

PLEDGED EQUITY

Grantor	Issuer	Class of Equity	Certificate No(s)	Number of Shares	Percentage of Outstanding Shares
SandRidge Energy, Inc.	Lariat Services, Inc.	Common Stock	1	100,000	100%
SandRidge Energy, Inc.	SandRidge CO2, LLC	Membership Interests	n/a	n/a	100%
SandRidge Energy, Inc.	SandRidge Holdings, Inc.	Common Stock	1	100	100%
SandRidge Energy, Inc.	SandRidge Midstream, Inc.	Common Stock	1	100,000	100%
SandRidge Energy, Inc.	SandRidge Operating Company	Common Stock	1	100,000	100%
SandRidge Energy, Inc.	SandRidge Realty, LLC	Membership Interests	n/a	n/a	100%
Integra Energy, L.L.C.	Cholla Pipeline, L.P.	Limited Partnership	n/a	n/a	36.1427%
SandRidge Holdings, Inc.	SandRidge Exploration and Production, LLC	Membership Interests	n/a	n/a	100%
SandRidge Exploration and Production, LLC	Integra Energy, L.L.C.	Membership Interests	n/a	n/a	100%
SandRidge Midstream, Inc.	Cholla Pipeline, L.P.	Limited Partnership Interests	n/a	n/a	62.5716%
SandRidge Midstream, Inc.	Sagebrush Pipeline, LLC	Membership Interests	n/a	n/a	73.80881%

Schedule II

Exhibit A to the Security Agreement

FORM OF PLEDGE AND SECURITY AGREEMENT SUPPLEMENT

[Date of Pledge and Security Agreement Supplement]

ROYAL BANK OF CANADA

as the Administrative Agent for the Secured Parties referred to in the Credit Agreement referred to below

200 Bay Street

Toronto, ON M5J 2W7

SandRidge Energy Inc.

Ladies and Gentlemen:

Reference is made to (i) Credit Agreement dated as of October 4, 2016 (as amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”), among SandRidge Energy Inc., the Lenders party thereto and Royal Bank of Canada, as Administrative Agent (together with any successor Administrative Agent appointed pursuant to the Credit Agreement, the “Administrative Agent”) and L/C Issuer and (ii) the Pledge and Security Agreement dated as of October 4, 2016 (as amended, amended and restated, supplemented or otherwise modified from time to time, the “Security Agreement”) made by the Grantors from time to time party thereto in favor of the Administrative Agent for the Secured Parties. Terms defined in the Credit Agreement or the Security Agreement and not otherwise defined herein are used herein as defined in the Credit Agreement or the Security Agreement.

SECTION 1. Grant of Security. The undersigned hereby grants to the Administrative Agent, for the ratable benefit of the Secured Parties, a security interest in, all of its right, title and interest in and to all of the Collateral of the undersigned, whether now owned or hereafter acquired by the undersigned, wherever located and whether now or hereafter existing or arising, including the property and assets of the undersigned set forth on the attached supplemental schedules to the Schedules to the Security Agreement.

SECTION 2. Security for Obligations. The grant of a security interest in, the Collateral by the undersigned under this Security Agreement Supplement and the Security Agreement secures the payment of all Obligations of any Loan Party that are now or hereafter existing under or in respect of the Loan Documents and all Obligations of any Loan Party under Lender Contracts that are now or hereafter existing, in each case whether direct or indirect, absolute or contingent, and whether for principal, reimbursement obligations, interest, premiums, penalties, fees, indemnifications, contract causes of action, costs, expenses or otherwise.

SECTION 3. Supplements to Security Agreement Schedules. The undersigned has attached hereto supplemental Schedules to the respective Schedules to the Security Agreement, and the undersigned hereby certifies, as of the date first above written, that such supplemental schedules have been prepared by the undersigned in substantially the form of the equivalent Schedules to the Security Agreement and are complete and correct.

SECTION 4. Representations and Warranties. The undersigned makes as of the date hereof each representation and warranty set forth in Section 6 of the Security Agreement (as supplemented by the attached supplemental schedules) to the same extent as each other Grantor.

SECTION 5. Obligations Under the Security Agreement. The undersigned hereby agrees, as of the date first above written, to be bound as a Grantor by all of the terms and provisions of the Security Agreement to the same extent as each of the other Grantors. The undersigned further agrees, as of the date first above written, that each reference in the Security Agreement to an “Additional Grantor” or a “Grantor” shall also mean and be a reference to the undersigned.

A-1

SECTION 6. Governing Law. This Security Agreement Supplement shall be governed by, and construed in accordance with, the laws of the State of New York.

Very truly yours,

[NAME OF ADDITIONAL GRANTOR]

By:

Name:

Title:

Address for notices:

____________________________________________

____________________________________________

A-2

EX-10.1.1

Exhibit 10.1.1

RESTRICTED STOCK AGREEMENT

PURSUANT TO THE

SANDRIDGE ENERGY, INC. 2016 OMNIBUS INCENTIVE PLAN

* * * * *

Participant: [●]

Grant Date: [●]

Number of Shares of

Restricted Stock Granted: [●]

Award Share Price*: $[●]            

*Based on the ten-day volume weighted average price of the Common Stock from October 5, 2016 through October 18, 2016.

* * * * *

THIS RESTRICTED STOCK AWARD AGREEMENT (this “Agreement”), dated as of the Grant Date specified above, is entered into by and between SandRidge Energy, Inc., a corporation organized in the State of Delaware (the “Company”), and the Participant specified above, pursuant to the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, as in effect and as amended from time to time (the “Plan”), which is administered by the Committee; and

WHEREAS, it has been determined under the Plan that it would be in the best interests of the Company to grant the shares of Restricted Stock provided herein to the Participant.

NOW, THEREFORE, in consideration of the mutual covenants and promises hereinafter set forth and for other good and valuable consideration, the parties hereto hereby mutually covenant and agree as follows:

1.Incorporation By Reference; Plan Document Receipt. This Agreement is subject in all respects to the terms and provisions of the Plan (including, without limitation, any amendments thereto adopted at any time and from time to time, unless such amendments are (a) expressly intended not to apply to the Award provided hereunder or (b) impair the Participant’s rights with respect to this Award without the consent of the Participant), all of which terms and provisions are made a part of and incorporated in this Agreement as if they were each expressly set forth herein. Any capitalized term not defined in this Agreement shall have the same meaning as is ascribed thereto in the Plan. The Participant hereby acknowledges receipt of a true copy of the Plan and that the Participant has read the Plan carefully and fully understands its content. In the event of any conflict between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control.

1

2.Grant of Restricted Stock. The Company hereby grants to the Participant, as of the Grant Date specified above, the number of shares of Restricted Stock specified above. Except as otherwise provided by the Plan, the Participant agrees and understands that nothing contained in this Agreement provides, or is intended to provide, the Participant with any protection against potential future dilution of the Participant’s interest in the Company for any reason, and no adjustments shall be made for dividends in cash or other property, distributions or other rights in respect of any such shares, except as otherwise specifically provided for in the Plan or this Agreement. Subject to Section 5 hereof, the Participant shall not have the rights of a stockholder in respect of the shares underlying this Award, until such shares are delivered to the Participant in accordance with Section 4 hereof.

3.Vesting.

(a)Subject to the provisions of Sections 3(b) through 3(c) hereof, the Restricted Stock shall vest as to one-third of the Restricted Stock on each of the first three anniversaries of the Grant Date (each, a “Vesting Date”); provided that the Participant has not experienced a Termination of Directorship prior to the applicable Vesting Date. Except as provided in this Agreement and/or under an effective employment agreement between the Company and the Participant, there shall be no proportionate or partial vesting in the periods prior to each Vesting Date, and all vesting shall occur only on the appropriate Vesting Date, subject to the Participant’s continued service with the Company or any of its Subsidiaries on the applicable Vesting Date.

(b)Change in Control Vesting. The Restricted Stock shall fully vest as of the consummation of a Change in Control, provided that the Participant has not experienced a Termination of Directorship prior to the consummation of the Change in Control.

(c)Committee Discretion to Accelerate Vesting. Notwithstanding the foregoing, the Committee may, in its sole discretion, provide for accelerated vesting of the Restricted Stock at any time and for any reason.

(d)Forfeiture. Subject to the Committee’s discretion to accelerate vesting hereunder and/or any accelerated vesting provided under an effective employment agreement between the Company and the Participant, all unvested shares of Restricted Stock shall be immediately forfeited upon the Participant’s Termination of Directorship for any reason.

4.Period of Restriction; Delivery of Unrestricted Shares. During the Period of Restriction, the Restricted Stock shall bear a legend as described in Section 7.2(c) of the Plan. When shares of Restricted Stock awarded by this Agreement become vested, the Participant shall be entitled to receive unrestricted shares, and if the Participant’s stock certificates contain legends restricting the transfer of such shares, the Participant shall be entitled to receive new stock certificates free of such legends (except any legends requiring compliance with securities laws).

5.Dividends and Other Distributions; Voting.Participantsholding Restricted Stock shall be entitled to receive all dividends and other distributions paid with respect to such shares, provided that any such dividends or other distributions will be subject to the same vesting requirements as the underlying Restricted Stock and shall be paid at the time the Restricted

2

Stock becomes vested pursuant to Section 3 hereof. If any dividends or distributions are paid in shares, the shares shall be deposited with the Company and shall be subject to the same restrictions on transferability and forfeitability as the Restricted Stock with respect to which they were paid. The Participant may exercise full voting rights with respect to the Restricted Stock granted hereunder.

6.Non-Transferability. The shares of Restricted Stock, and any rights and interests with respect thereto, issued under this Agreement and the Plan shall not, prior to vesting, be sold, exchanged, transferred, assigned or otherwise disposed of in any way by the Participant (or any beneficiary of the Participant), other than by testamentary disposition by the Participant or the laws of descent and distribution. Any attempt to sell, exchange, transfer, assign, pledge, encumber or otherwise dispose of or hypothecate in any way any of the Restricted Stock, or the levy of any execution, attachment or similar legal process upon the Restricted Stock, contrary to the terms and provisions of this Agreement and/or the Plan, shall be null and void and without legal force or effect.

7.Governing Law. All questions concerning the construction, validity and interpretation of this Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to the choice of law principles thereof.

8.Withholding of Tax. The Company shall have the power and the right to deduct or withhold, or require the Participant to remit to the Company, an amount sufficient to satisfy any federal, state, local and foreign taxes of any kind (including, but not limited to, the Participant’s FICA and SDI obligations) which the Company, in its sole discretion, deems necessary to be withheld or remitted to comply with the Code and/or any other applicable law, rule or regulation with respect to the Restricted Stock and, if the Participant fails to do so, the Company may otherwise refuse to issue or transfer any shares of Common Stock otherwise required to be issued pursuant to this Agreement. Any minimum statutorily required withholding obligation with regard to the Participant may be satisfied by reducing the amount of cash or shares of Common Stock otherwise deliverable to the Participant hereunder.

9.Section 83(b). If the Participant properly elects (as required by Section 83(b) of the Code) within 30 days after the issuance of the Restricted Stock to include in gross income for federal income tax purposes in the year of issuance the Fair Market Value of such shares of Restricted Stock, the Participant shall pay to the Company or make arrangements satisfactory to the Company to pay to the Company upon such election, any federal, state or local taxes required to be withheld with respect to the Restricted Stock. If the Participant shall fail to make such payment, the Company shall, to the extent permitted by law, have the right to deduct from any payment of any kind otherwise due to the Participant any federal, state or local taxes of any kind required by law to be withheld with respect to the Restricted Stock, as well as the rights set forth in Section 8 hereof. The Participant acknowledges that it is the Participant’s sole responsibility, and not the Company’s, to file timely and properly the election under Section 83(b) of the Code and any corresponding provisions of state tax laws if the Participant elects to make such election, and the Participant agrees to timely provide the Company with a copy of any such election.

10.Legend. All certificates representing the Restricted Stock shall have endorsed thereon the legend set forth in Section 7.2(c) of the Plan. Notwithstanding the foregoing,

3

in no event shall the Company be obligated to deliver to the Participant a certificate representing the Restricted Stock prior to the vesting dates set forth above.

11.Securities Representations. The shares of Restricted Stock are being issued to the Participant and this Agreement is being made by the Company in reliance upon the following express representations and warranties of the Participant. The Participant acknowledges, represents and warrants that:

(a)The Participant has been advised that the Participant may be an “affiliate” within the meaning of Rule 144 under the Securities Act and in this connection the Company is relying in part on the Participant’s representations set forth in this Section 11.

(b)If the Participant is deemed an affiliate within the meaning of Rule 144 of the Securities Act, the shares of Restricted Stock must be held indefinitely unless an exemption from any applicable resale restrictions is available or the Company files an additional registration statement (or a “re-offer prospectus”) with regard to the shares of Restricted Stock and the Company is under no obligation to register the shares of Restricted Stock (or to file a “re-offer prospectus”).

(c)If the Participant is deemed an affiliate within the meaning of Rule 144 of the Securities Act, the Participant understands that (i) the exemption from registration under Rule 144 will not be available unless (A) a public trading market then exists for the Common Stock of the Company, (B) adequate information concerning the Company is then available to the public, and (C) other terms and conditions of Rule 144 or any exemption therefrom are complied with, and (ii) any sale of the shares of vested Restricted Stock hereunder may be made only in limited amounts in accordance with the terms and conditions of Rule 144 or any exemption therefrom.

12.Entire Agreement; Amendment. This Agreement, together with the Plan, contains the entire agreement between the parties hereto with respect to the subject matter contained herein, and supersedes all prior agreements or prior understandings, whether written or oral, between the parties relating to such subject matter; provided that to the extent the Participant is party to an effective employment agreement with the Company, the terms set forth therein shall govern in the event of a conflict with Section 3 of this Agreement. The Committee shall have the right, in its sole discretion, to modify or amend this Agreement from time to time in accordance with and as provided in the Plan. This Agreement may also be modified or amended by a writing signed by both the Company and the Participant. The Company shall give written notice to the Participant of any such modification or amendment of this Agreement as soon as practicable after the adoption thereof.

13.Notices.Any notice hereunder by the Participant shall be given to the Company in writing and such notice shall be deemed duly given only upon receipt thereof by the General Counsel of the Company. Any notice hereunder by the Company shall be given to the Participant in writing and such notice shall be deemed duly given only upon receipt thereof at such address as the Participant may have on file with the Company.

14.Acceptance. The Participant shall be deemed to accept this Agreement unless the Participant provides the Company with written notice to the contrary prior to the expiration

4

of the 60-day period following the Grant Date, in which case, the Participant shall forfeit the Restricted Stock

15.No Right to Continued Service. Any questions as to whether and when there has been a Termination of Directorship and the cause of such Termination of Directorship shall be determined in the sole discretion of the Committee. Nothing in this Agreement shall interfere with or limit in any way the right of the Company, its Subsidiaries or Affiliates to terminate the Participant’s service at any time, for any reason and with or without Cause.

16.Transfer of Personal Data. The Participant authorizes, agrees and unambiguously consents to the transmission by the Company (or any Subsidiary) of any personal data information related to the Restricted Stock awarded under this Agreement for legitimate business purposes (including, without limitation, the administration of the Plan). This authorization and consent is freely given by the Participant.

17.Compliance with Laws. The issuance of the Restricted Stock or unrestricted shares pursuant to this Agreement shall be subject to, and shall comply with, any applicable requirements of any foreign and U.S. federal and state securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act, the Exchange Act and in each case any respective rules and regulations promulgated thereunder) and any other law or regulation applicable thereto. The Company shall not be obligated to issue the Restricted Stock or any of the shares pursuant to this Agreement if any such issuance would violate any such requirements.

18.Section 409A. Notwithstanding anything herein or in the Plan to the contrary, the shares of Restricted Stock are intended to be exempt from the applicable requirements of Section 409A of the Code and shall be limited, construed and interpreted in accordance with such intent.

19.Binding Agreement; Assignment. This Agreement shall inure to the benefit of, be binding upon, and be enforceable by the Company and its successors and assigns. The Participant shall not assign (except in accordance with Section 6 hereof) any part of this Agreement without the prior express written consent of the Company.

20.Headings. The titles and headings of the various sections of this Agreement have been inserted for convenience of reference only and shall not be deemed to be a part of this Agreement.

21.Further Assurances. Each party hereto shall do and perform (or shall cause to be done and performed) all such further acts and shall execute and deliver all such other agreements, certificates, instruments and documents as either party hereto reasonably may request in order to carry out the intent and accomplish the purposes of this Agreement and the Plan and the consummation of the transactions contemplated thereunder.

22.Severability. The invalidity or unenforceability of any provisions of this Agreement in any jurisdiction shall not affect the validity, legality or enforceability of the remainder of this Agreement in such jurisdiction or the validity, legality or enforceability of any provision of

5

this Agreement in any other jurisdiction, it being intended that all rights and obligations of the parties hereunder shall be enforceable to the fullest extent permitted by law.

23.Acquired Rights. The Participant acknowledges and agrees that: (a) the Company may terminate or amend the Plan at any time; (b) the award of Restricted Stock made under this Agreement is completely independent of any other award or grant and is made at the sole discretion of the Company; (c) no past grants or awards (including, without limitation, the Restricted Stock awarded hereunder) give the Participant any right to any grants or awards in the future whatsoever; and (d) any benefits granted under this Agreement are not part of the Participant’s ordinary compensation and shall not be considered as part of such compensation for any reason.

[Remainder of Page Intentionally Left Blank]

6

IN WITNESS WHEREOF, the Company has issued the Restricted Stock to the Participant as of the date first written above.

SANDRIDGE ENERGY, INC.

By:

Name:    James D. Bennett            

Title:    President & Chief Executive Officer    

7

EX-10.1.2

Exhibit 10.1.2

RESTRICTED STOCK AGREEMENT

PURSUANT TO THE

SANDRIDGE ENERGY, INC. 2016 OMNIBUS INCENTIVE PLAN

* * * * *

Participant: [●]

Grant Date: [●]

Number of Shares of

Restricted Stock Granted: [●]

Award Share Price*: $[●]            

*Based on the ten-day volume weighted average price of the Common Stock from October 5, 2016 through October 18, 2016.

* * * * *

THIS RESTRICTED STOCK AWARD AGREEMENT (this “Agreement”), dated as of the Grant Date specified above, is entered into by and between SandRidge Energy, Inc., a corporation organized in the State of Delaware (the “Company”), and the Participant specified above, pursuant to the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, as in effect and as amended from time to time (the “Plan”), which is administered by the Committee; and

WHEREAS, it has been determined under the Plan that it would be in the best interests of the Company to grant the shares of Restricted Stock provided herein to the Participant.

NOW, THEREFORE, in consideration of the mutual covenants and promises hereinafter set forth and for other good and valuable consideration, the parties hereto hereby mutually covenant and agree as follows:

1.Incorporation By Reference; Plan Document Receipt. This Agreement is subject in all respects to the terms and provisions of the Plan (including, without limitation, any amendments thereto adopted at any time and from time to time, unless such amendments are (a) expressly intended not to apply to the Award provided hereunder or (b) impair the Participant’s rights with respect to this Award without the consent of the Participant), all of which terms and provisions are made a part of and incorporated in this Agreement as if they were each expressly set forth herein. Any capitalized term not defined in this Agreement shall have the same meaning as is ascribed thereto in the Plan. The Participant hereby acknowledges receipt of a true copy of the Plan and that the Participant has read the Plan carefully and fully understands its content. In the event of any conflict between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control.

1

2.Grant of Restricted Stock. The Company hereby grants to the Participant, as of the Grant Date specified above, the number of shares of Restricted Stock specified above. Except as otherwise provided by the Plan, the Participant agrees and understands that nothing contained in this Agreement provides, or is intended to provide, the Participant with any protection against potential future dilution of the Participant’s interest in the Company for any reason, and no adjustments shall be made for dividends in cash or other property, distributions or other rights in respect of any such shares, except as otherwise specifically provided for in the Plan or this Agreement. Subject to Section 5 hereof, the Participant shall not have the rights of a stockholder in respect of the shares underlying this Award, until such shares are delivered to the Participant in accordance with Section 4 hereof.

3.Vesting.

(a)Subject to the provisions of Sections 3(b) through 3(c) hereof, the Restricted Stock shall vest as to one-third of the Restricted Stock on each of the first three anniversaries of the Grant Date (each, a “Vesting Date”); provided that the Participant has not experienced a Termination prior to the applicable Vesting Date. Except as provided in this Agreement and/or under an effective employment agreement between the Company and the Participant, there shall be no proportionate or partial vesting in the periods prior to each Vesting Date, and all vesting shall occur only on the appropriate Vesting Date, subject to the Participant’s continued service with the Company or any of its Subsidiaries on the applicable Vesting Date.

(b)Change in Control Vesting. The Restricted Stock shall fully vest as of the consummation of a Change in Control, provided that the Participant has not experienced a Termination prior to the consummation of the Change in Control.

(c)Committee Discretion to Accelerate Vesting. Notwithstanding the foregoing, the Committee may, in its sole discretion, provide for accelerated vesting of the Restricted Stock at any time and for any reason.

(d)Forfeiture. Subject to the Committee’s discretion to accelerate vesting hereunder and/or any accelerated vesting provided under an effective employment agreement between the Company and the Participant, all unvested shares of Restricted Stock shall be immediately forfeited upon the Participant’s Termination for any reason.

4.Period of Restriction; Delivery of Unrestricted Shares. During the Period of Restriction, the Restricted Stock shall bear a legend as described in Section 7.2(c) of the Plan. When shares of Restricted Stock awarded by this Agreement become vested, the Participant shall be entitled to receive unrestricted shares, and if the Participant’s stock certificates contain legends restricting the transfer of such shares, the Participant shall be entitled to receive new stock certificates free of such legends (except any legends requiring compliance with securities laws).

5.Dividends and Other Distributions; Voting.Participantsholding Restricted Stock shall be entitled to receive all dividends and other distributions paid with respect to such shares, provided that any such dividends or other distributions will be subject to the same vesting requirements as the underlying Restricted Stock and shall be paid at the time the Restricted

2

Stock becomes vested pursuant to Section 3 hereof. If any dividends or distributions are paid in shares, the shares shall be deposited with the Company and shall be subject to the same restrictions on transferability and forfeitability as the Restricted Stock with respect to which they were paid. The Participant may exercise full voting rights with respect to the Restricted Stock granted hereunder.

6.Non-Transferability. The shares of Restricted Stock, and any rights and interests with respect thereto, issued under this Agreement and the Plan shall not, prior to vesting, be sold, exchanged, transferred, assigned or otherwise disposed of in any way by the Participant (or any beneficiary of the Participant), other than by testamentary disposition by the Participant or the laws of descent and distribution. Any attempt to sell, exchange, transfer, assign, pledge, encumber or otherwise dispose of or hypothecate in any way any of the Restricted Stock, or the levy of any execution, attachment or similar legal process upon the Restricted Stock, contrary to the terms and provisions of this Agreement and/or the Plan, shall be null and void and without legal force or effect.

7.Governing Law. All questions concerning the construction, validity and interpretation of this Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to the choice of law principles thereof.

8.Withholding of Tax. The Company shall have the power and the right to deduct or withhold, or require the Participant to remit to the Company, an amount sufficient to satisfy any federal, state, local and foreign taxes of any kind (including, but not limited to, the Participant’s FICA and SDI obligations) which the Company, in its sole discretion, deems necessary to be withheld or remitted to comply with the Code and/or any other applicable law, rule or regulation with respect to the Restricted Stock and, if the Participant fails to do so, the Company may otherwise refuse to issue or transfer any shares of Common Stock otherwise required to be issued pursuant to this Agreement. Any minimum statutorily required withholding obligation with regard to the Participant may be satisfied by reducing the amount of cash or shares of Common Stock otherwise deliverable to the Participant hereunder.

9.Section 83(b). If the Participant properly elects (as required by Section 83(b) of the Code) within 30 days after the issuance of the Restricted Stock to include in gross income for federal income tax purposes in the year of issuance the Fair Market Value of such shares of Restricted Stock, the Participant shall pay to the Company or make arrangements satisfactory to the Company to pay to the Company upon such election, any federal, state or local taxes required to be withheld with respect to the Restricted Stock. If the Participant shall fail to make such payment, the Company shall, to the extent permitted by law, have the right to deduct from any payment of any kind otherwise due to the Participant any federal, state or local taxes of any kind required by law to be withheld with respect to the Restricted Stock, as well as the rights set forth in Section 8 hereof. The Participant acknowledges that it is the Participant’s sole responsibility, and not the Company’s, to file timely and properly the election under Section 83(b) of the Code and any corresponding provisions of state tax laws if the Participant elects to make such election, and the Participant agrees to timely provide the Company with a copy of any such election.

10.Legend. All certificates representing the Restricted Stock shall have endorsed thereon the legend set forth in Section 7.2(c) of the Plan. Notwithstanding the foregoing,

3

in no event shall the Company be obligated to deliver to the Participant a certificate representing the Restricted Stock prior to the vesting dates set forth above.

11.Securities Representations. The shares of Restricted Stock are being issued to the Participant and this Agreement is being made by the Company in reliance upon the following express representations and warranties of the Participant. The Participant acknowledges, represents and warrants that:

(a)The Participant has been advised that the Participant may be an “affiliate” within the meaning of Rule 144 under the Securities Act and in this connection the Company is relying in part on the Participant’s representations set forth in this Section 11.

(b)If the Participant is deemed an affiliate within the meaning of Rule 144 of the Securities Act, the shares of Restricted Stock must be held indefinitely unless an exemption from any applicable resale restrictions is available or the Company files an additional registration statement (or a “re-offer prospectus”) with regard to the shares of Restricted Stock and the Company is under no obligation to register the shares of Restricted Stock (or to file a “re-offer prospectus”).

(c)If the Participant is deemed an affiliate within the meaning of Rule 144 of the Securities Act, the Participant understands that (i) the exemption from registration under Rule 144 will not be available unless (A) a public trading market then exists for the Common Stock of the Company, (B) adequate information concerning the Company is then available to the public, and (C) other terms and conditions of Rule 144 or any exemption therefrom are complied with, and (ii) any sale of the shares of vested Restricted Stock hereunder may be made only in limited amounts in accordance with the terms and conditions of Rule 144 or any exemption therefrom.

12.Entire Agreement; Amendment. This Agreement, together with the Plan, contains the entire agreement between the parties hereto with respect to the subject matter contained herein, and supersedes all prior agreements or prior understandings, whether written or oral, between the parties relating to such subject matter; provided that to the extent the Participant is party to an effective employment agreement with the Company, the terms set forth therein shall govern in the event of a conflict with Section 3 of this Agreement. The Committee shall have the right, in its sole discretion, to modify or amend this Agreement from time to time in accordance with and as provided in the Plan. This Agreement may also be modified or amended by a writing signed by both the Company and the Participant. The Company shall give written notice to the Participant of any such modification or amendment of this Agreement as soon as practicable after the adoption thereof.

13.Notices.Any notice hereunder by the Participant shall be given to the Company in writing and such notice shall be deemed duly given only upon receipt thereof by the General Counsel of the Company. Any notice hereunder by the Company shall be given to the Participant in writing and such notice shall be deemed duly given only upon receipt thereof at such address as the Participant may have on file with the Company.

14.Acceptance. The Participant shall be deemed to accept this Agreement unless the Participant provides the Company with written notice to the contrary prior to the expiration

4

of the 60-day period following the Grant Date, in which case, the Participant shall forfeit the Restricted Stock

15.No Right to Employment. Any questions as to whether and when there has been a Termination and the cause of such Termination shall be determined in the sole discretion of the Committee. Nothing in this Agreement shall interfere with or limit in any way the right of the Company, its Subsidiaries or Affiliates to terminate the Participant’s employment or service at any time, for any reason and with or without Cause.

16.Transfer of Personal Data. The Participant authorizes, agrees and unambiguously consents to the transmission by the Company (or any Subsidiary) of any personal data information related to the Restricted Stock awarded under this Agreement for legitimate business purposes (including, without limitation, the administration of the Plan). This authorization and consent is freely given by the Participant.

17.Compliance with Laws. The issuance of the Restricted Stock or unrestricted shares pursuant to this Agreement shall be subject to, and shall comply with, any applicable requirements of any foreign and U.S. federal and state securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act, the Exchange Act and in each case any respective rules and regulations promulgated thereunder) and any other law or regulation applicable thereto. The Company shall not be obligated to issue the Restricted Stock or any of the shares pursuant to this Agreement if any such issuance would violate any such requirements.

18.Section 409A. Notwithstanding anything herein or in the Plan to the contrary, the shares of Restricted Stock are intended to be exempt from the applicable requirements of Section 409A of the Code and shall be limited, construed and interpreted in accordance with such intent.

19.Binding Agreement; Assignment. This Agreement shall inure to the benefit of, be binding upon, and be enforceable by the Company and its successors and assigns. The Participant shall not assign (except in accordance with Section 6 hereof) any part of this Agreement without the prior express written consent of the Company.

20.Headings. The titles and headings of the various sections of this Agreement have been inserted for convenience of reference only and shall not be deemed to be a part of this Agreement.

21.Further Assurances. Each party hereto shall do and perform (or shall cause to be done and performed) all such further acts and shall execute and deliver all such other agreements, certificates, instruments and documents as either party hereto reasonably may request in order to carry out the intent and accomplish the purposes of this Agreement and the Plan and the consummation of the transactions contemplated thereunder.

22.Severability. The invalidity or unenforceability of any provisions of this Agreement in any jurisdiction shall not affect the validity, legality or enforceability of the remainder of this Agreement in such jurisdiction or the validity, legality or enforceability of any provision of

5

this Agreement in any other jurisdiction, it being intended that all rights and obligations of the parties hereunder shall be enforceable to the fullest extent permitted by law.

23.Acquired Rights. The Participant acknowledges and agrees that: (a) the Company may terminate or amend the Plan at any time; (b) the award of Restricted Stock made under this Agreement is completely independent of any other award or grant and is made at the sole discretion of the Company; (c) no past grants or awards (including, without limitation, the Restricted Stock awarded hereunder) give the Participant any right to any grants or awards in the future whatsoever; and (d) any benefits granted under this Agreement are not part of the Participant’s ordinary salary and shall not be considered as part of such salary in the event of severance, redundancy or resignation.

[Remainder of Page Intentionally Left Blank]

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IN WITNESS WHEREOF, the Company has issued the Restricted Stock to the Participant as of the date first written above.

SANDRIDGE ENERGY, INC.

By:

Name:    James D. Bennett            

Title:    President & Chief Executive Officer    

7

EX-10.1.3

Exhibit 10.1.3

PERFORMANCE UNIT AWARD AGREEMENT

PURSUANT TO THE

SANDRIDGE ENERGY, INC. 2016 OMNIBUS INCENTIVE PLAN

* * * * *

Participant: [●]

Grant Date: [●]    

Total Number of Performance Units Awarded: [●]

Target Value of Each Performance Unit (the “Target Value”): $100.00

Maximum Value of Each Performance Unit (the “Maximum Value”): $200.00

* * * * *

THIS PERFORMANCE UNIT AWARD AGREEMENT (this “Agreement”), dated as of the Grant Date specified above, is entered into by and between SandRidge Energy, Inc., a corporation organized in the State of Delaware (the “Company”), and the Participant specified above, pursuant to the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, as in effect and as amended from time to time (the “Plan”), which is administered by the Committee; and

WHEREAS, it has been determined under the Plan that it would be in the best interests of the Company to grant the Performance Units (“PUs”) provided herein to the Participant.

NOW, THEREFORE, in consideration of the mutual covenants and promises hereinafter set forth and for other good and valuable consideration, the parties hereto hereby mutually covenant and agree as follows:

1.Incorporation By Reference; Plan Document Receipt. This Agreement is subject in all respects to the terms and provisions of the Plan (including, without limitation, any amendments thereto adopted at any time and from time to time, unless such amendments are (a) expressly intended not to apply to the Award provided hereunder or (b) impair the Participant’s rights with respect to this Award without the consent of the Participant), all of which terms and provisions are made a part of and incorporated in this Agreement as if they were each expressly set forth herein. Except as provided otherwise herein, any capitalized term not defined in this Agreement shall have the same meaning as is ascribed thereto in the Plan. The Participant hereby acknowledges receipt of a true copy of the Plan and that the Participant has read the Plan carefully and fully understands its content. In the event of any conflict between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control.

2.Grant of Performance Unit Award. The Company hereby grants to the Participant, as of the Grant Date specified above, the total number of PUs specified above, each of which has the Target Value specified above, with the actual value to be paid out per PU pursuant to this Award

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contingent upon satisfaction of the vesting conditions described in Section 3 hereof, subject to Section 4, but not to exceed the Maximum Value.

3.Vesting.

(a)The PUs subject to this Award shall be subject to both a time-based vesting condition (the “Time-Based Condition”) and a performance-based vesting condition (the “Performance Condition”), as described herein. Except as expressly provided herein, none of the PUs shall be “vested” for purposes of this Agreement (i.e., the PUs shall not have any value), unless and until both the Time-Based Condition and the Performance Condition for such PUs are satisfied. The value of the PUs that are “vested” for purposes of this Agreement at any time shall equal the product of (i) the number of the PUs that have satisfied the Time-Based Condition and (ii) the value per PU (the “Vested PU Value”) given the level at which the Performance Condition has been satisfied for the applicable Performance Period.

(i)The Time-Based Condition for one-third of the PUs shall be satisfied on each of December 31, 2017, December 31, 2018 and December 31, 2019 (each, a “Time Vesting Date”), subject to the Participant not incurring a Termination prior to the applicable Time Vesting Date. Except as provided in this Agreement and/or under an effective employment agreement between the Company and the Participant, there shall be no proportionate or partial satisfaction of the Time-Based Condition prior to the applicable Vesting Date; for the avoidance of doubt, this Award shall be treated as an equity award for purposes of any accelerated vesting provided in an employment agreement.

(ii)The Vested PU Value shall be based upon the level at which the performance goal(s) designated in the scorecard for the applicable Performance Period (the “Scorecard”) is/are satisfied, which Scorecard shall be prepared by the Committee and communicated to the Participant within the first 90 days following commencement of the applicable Performance Period. The “First Performance Period” shall be January 1, 2017 through December 31, 2017; the “Second Performance Period” shall be January 1, 2018 through December 31, 2018; and the “Third Performance Period” shall be January 1, 2019 through December 31, 2019. Notwithstanding anything to the contrary in the Scorecard, the PUs shall only vest if the Company’s earnings before interest, tax, depreciation and amortization exceed $1.00 in any of the First Performance Period, the Second Performance Period or the Third Performance Period.

For the avoidance of doubt, in no event shall the Performance Condition be deemed satisfied unless actual performance equals or exceeds the threshold level provided in the applicable Scorecard. To the extent that the actual performance is between the threshold and target levels or between the target and maximum levels described in the Scorecard, the Vested PU Value shall be determined as set forth in the Scorecard; provided that the Performance Condition shall not be satisfied and the Vested PU Value shall be zero, if the actual performance is less than the threshold

    2

level of performance; and provided, further, that the maximum Vested PU Value shall not exceed 200% of the Target Value.

(b)Change in Control.For the avoidance of doubt, (i) a Change in Control shall result in 100% accelerated vesting of the PUs at Target Value, and (ii) in connection with a Change in Control or any other event described in Section 4.2 of the Plan, the Committee shall have the discretion to adjust the PUs and the Performance Condition as provided in the Plan.

(c)Forfeiture. All PUs for which the Time-Based Condition has not been satisfied prior to a Participant’s Termination for any reason shall be immediately forfeited upon such Termination and the Participant shall have no further rights to such PUs hereunder. Any PUs that do not attain any Vested PU Value as of the end of the applicable Performance Period shall expire immediately following the date that the Committee determines the level at which the Performance Condition is satisfied.

4.Payment of Cash. Following the satisfaction of both the Time-Based Condition and the Performance Condition with respect to any part of the PUs granted hereunder, the Participant shall receive an amount in cash equal to the product of (i) the number of such vested PUs, multiplied by (ii) the Vested PU Value, which amount shall be paid to the Participant within thirty (30) days of the Committee’s certification of the extent to which the performance goals for the applicable Performance Period have been met, but in any event no later than March 15 of the calendar year following the calendar year in which or with respect to which both such vesting conditions were satisfied.

5.Non-Transferability. No portion of the PUs may be sold, assigned, transferred, encumbered, hypothecated or pledged by the Participant, other than to the Company as a result of forfeiture of the PUs as provided herein.

6.Governing Law. All questions concerning the construction, validity and interpretation of this Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to the choice of law principles thereof.

7.Withholding of Tax. The Participant agrees and acknowledges that the Company shall deduct or withhold from the cash payment due with respect to the vesting of the PUs an amount sufficient to satisfy any federal, state, local and foreign taxes of any kind (including, but not limited to, the Participant’s FICA and SDI obligations) which the Company, in its sole discretion, deems necessary to be withheld or remitted to comply with the Code and/or any other applicable law, rule or regulation with respect to the PUs.

8.Entire Agreement; Amendment. This Agreement, together with the Plan, contains the entire agreement between the parties hereto with respect to the subject matter contained herein, and supersedes all prior agreements or prior understandings, whether written or oral, between the parties relating to such subject matter; provided that to the extent the Participant is party to an effective employment agreement with the Company, the terms set forth therein applicable to equity awards shall govern in the event of a conflict with Section 3 of this Agreement. The Committee

    3

shall have the right, in its sole discretion, to modify or amend this Agreement from time to time in accordance with and as provided in the Plan. This Agreement may also be modified or amended by a writing signed by both the Company and the Participant. The Company shall give written notice to the Participant of any such modification or amendment of this Agreement as soon as practicable after the adoption thereof.

9.Notices. Any notice hereunder by the Participant shall be given to the Company in writing and such notice shall be deemed duly given only upon receipt thereof by the General Counsel of the Company. Any notice hereunder by the Company shall be given to the Participant in writing and such notice shall be deemed duly given only upon receipt thereof at such address as the Participant may have on file with the Company.

10.No Right to Employment. Any questions as to whether and when there has been a Termination and the cause of such Termination shall be determined in the sole discretion of the Committee. Nothing in this Agreement shall interfere with or limit in any way the right of the Company, its Subsidiaries or its Affiliates to terminate the Participant’s employment or service at any time, for any reason and with or without Cause.

11.Transfer of Personal Data. The Participant authorizes, agrees and unambiguously consents to the transmission by the Company (or any Subsidiary) of any personal data information related to the PUs awarded under this Agreement for legitimate business purposes. This authorization and consent is freely given by the Participant.

12.Compliance with Laws. The grant of PUs hereunder shall be subject to, and shall comply with, any applicable requirements of any foreign and U.S. federal and state securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act, the Exchange Act and in each case any respective rules and regulations promulgated thereunder) and any other law, rule regulation or exchange requirement applicable thereto. The Company shall not be obligated to issue the PUs or pay any amounts due pursuant to this Agreement if any such issuance or payment would violate any such requirements. As a condition to the settlement of the PUs, the Company may require the Participant to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation.

13.Section 409A. Notwithstanding anything herein or in the Plan to the contrary, the PUs are intended to be exempt from the applicable requirements of Section 409A of the Code and shall be limited, construed and interpreted in accordance with such intent as is reasonable under the circumstances.

14.Binding Agreement; Assignment. This Agreement shall inure to the benefit of, be binding upon, and be enforceable by the Company and its successors and assigns. The Participant shall not assign any part of this Agreement without the prior express written consent of the Company.

15.Headings. The titles and headings of the various sections of this Agreement have been inserted for convenience of reference only and shall not be deemed to be a part of this Agreement.

    4

16.Further Assurances. Each party hereto shall do and perform (or shall cause to be done and performed) all such further acts and shall execute and deliver all such other agreements, certificates, instruments and documents as either party hereto reasonably may request in order to carry out the intent and accomplish the purposes of this Agreement and the Plan and the consummation of the transactions contemplated thereunder.

17.Severability. The invalidity or unenforceability of any provisions of this Agreement in any jurisdiction shall not affect the validity, legality or enforceability of the remainder of this Agreement in such jurisdiction or the validity, legality or enforceability of any provision of this Agreement in any other jurisdiction, it being intended that all rights and obligations of the parties hereunder shall be enforceable to the fullest extent permitted by law.

18.Acquired Rights. The Participant acknowledges and agrees that: (a) the Company may terminate or amend the Plan at any time; (b) the Award of PUs made under this Agreement is completely independent of any other award or grant and is made at the sole discretion of the Company; (c) no past grants or awards (including, without limitation, the PUs awarded hereunder) give the Participant any right to any grants or awards in the future whatsoever; and (d) any benefits granted under this Agreement are not part of the Participant’s ordinary salary, and shall not be considered as part of such salary in the event of severance, redundancy or resignation.

* * * * *

    5

IN WITNESS WHEREOF, the Company has issued the Performance Units to the Participant pursuant to this Agreement as of the date first written above.

SANDRIDGE ENERGY, INC.

By:

Name:    James D. Bennett            

Title:    President & Chief Executive Officer    

Signature Page to Performance Unit Award Agreement

EX-10.1.4

Exhibit 10.1.4

	SandRidge Energy, Inc.
	123 Robert S. Kerr Avenue
	Oklahoma City, Oklahoma73102

Restricted Stock Award Certificate and Agreement

Name:	[●]	Award Number:	[●]
Address:	[●]	Plan:	2016 Omnibus Incentive Plan
		Employee ID:	[●]

Effective [GRANT DATE] (the “Grant Date”), you have been granted an Award of [NUMBER OF SHARES GRANTED] shares of SandRidge Energy, Inc. (the “Company”) restricted common stock. The Award is scheduled to vest in increments on the date(s) shown below.

VEST DATE	SHARES
[●]	[●]
[●]	[●]
[●]	[●]

This Award is granted under and governed by the terms and conditions of the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan and the Performance Share Unit Award Agreement. A copy of the Plan can be found under the Department – People & Culture tab of the Company’s intranet.

RESTRICTED STOCK AWARD AGREEMENT

PURSUANT TO THE

SANDRIDGE ENERGY, INC. 2016 OMNIBUS INCENTIVE PLAN

THIS RESTRICTED STOCK AWARD AGREEMENT (this “Agreement”), dated as of the Grant Date specified in the Restricted Stock Award Certificate attached hereto (the “Certificate”), is entered into by and between SandRidge Energy, Inc., a corporation organized in the State of Delaware (the “Company”), and the Participant specified above, pursuant to the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, as in effect and as amended from time to time (the “Plan”), which is administered by the Committee; and

WHEREAS, it has been determined under the Plan that it would be in the best interests of the Company to grant the shares of Restricted Stock provided herein to the Participant.

NOW, THEREFORE, in consideration of the mutual covenants and promises hereinafter set forth and for other good and valuable consideration, the parties hereto hereby mutually covenant and agree as follows:

1.Incorporation By Reference; Plan Document Receipt. This Agreement and the Certificate are subject in all respects to the terms and provisions of the Plan (including, without limitation, any amendments thereto adopted at any time and from time to time, unless such amendments are (a) expressly intended not to apply to the Award provided hereunder or (b) impair the Participant’s rights with respect to this Award without the consent of the Participant), all of which terms and provisions are made a part of and incorporated in this Agreement as if they were each expressly set forth herein. Any capitalized term not defined in this Agreement shall have the same meaning as is ascribed thereto in the Plan or the Certificate. The Participant hereby acknowledges receipt of a true copy of the Plan and that the Participant has read the Plan carefully and fully understands its content. In the event of any conflict between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control.

2.Grant of Restricted Stock. The Company hereby grants to the Participant, as of the Grant Date, the number of shares of Restricted Stock specified in the Certificate. Except as otherwise provided by the Plan, the Participant agrees and understands that nothing contained in this Agreement provides, or is intended to provide, the Participant with any protection against potential future dilution of the Participant’s interest in the Company for any reason, and no adjustments shall be made for dividends in cash or other property, distributions or other rights in respect of any such shares, except as otherwise specifically provided for in the Plan or this Agreement. Subject to Section 5 hereof, the Participant shall not have the rights of a stockholder in respect of the shares underlying this Award, until such shares are delivered to the Participant in accordance with Section 4 hereof.

3.Vesting.

(a)Subject to the provisions of Sections 3(b) through 3(c) hereof, the Restricted Stock shall vest in accordance with vesting schedule detailed in the Certificate; provided that the Participant has not experienced a Termination prior to an applicable Vesting Date. Except as provided in this Agreement and/or under an effective employment agreement between the Company and the Participant, there shall be no proportionate or partial vesting in the periods prior to each Vesting Date, and all vesting shall occur only on the appropriate Vesting Date, subject to the Participant’s continued service with the Company or any of its Subsidiaries on the applicable Vesting Date.

(b)Change in Control Vesting. The Restricted Stock shall fully vest as of the consummation of a Change in Control, provided that the Participant has not experienced a Termination prior to the consummation of the Change in Control.

2

(c)Committee Discretion to Accelerate Vesting. Notwithstanding the foregoing, the Committee may, in its sole discretion, provide for accelerated vesting of the Restricted Stock at any time and for any reason.

(d)Forfeiture. Subject to the Committee’s discretion to accelerate vesting hereunder and/or any accelerated vesting provided under an effective employment agreement between the Company and the Participant, all unvested shares of Restricted Stock shall be immediately forfeited upon the Participant’s Termination for any reason.

4.Period of Restriction; Delivery of Unrestricted Shares. During the Period of Restriction, the Restricted Stock shall bear a legend as described in Section 7.2(c) of the Plan. When shares of Restricted Stock awarded by this Agreement and the Certificate become vested, the Participant shall be entitled to receive unrestricted shares, and if the Participant’s stock certificates contain legends restricting the transfer of such shares, the Participant shall be entitled to receive new stock certificates free of such legends (except any legends requiring compliance with securities laws).

5.Dividends and Other Distributions; Voting.Participantsholding Restricted Stock shall be entitled to receive all dividends and other distributions paid with respect to such shares, provided that any such dividends or other distributions will be subject to the same vesting requirements as the underlying Restricted Stock and shall be paid at the time the Restricted Stock becomes vested pursuant to Section 3 hereof. If any dividends or distributions are paid in shares, the shares shall be deposited with the Company and shall be subject to the same restrictions on transferability and forfeitability as the Restricted Stock with respect to which they were paid. The Participant may exercise full voting rights with respect to the Restricted Stock granted hereunder.

6.Non-Transferability. The shares of Restricted Stock, and any rights and interests with respect thereto, issued under this Agreement, the Certificate and the Plan shall not, prior to vesting, be sold, exchanged, transferred, assigned or otherwise disposed of in any way by the Participant (or any beneficiary of the Participant), other than by testamentary disposition by the Participant or the laws of descent and distribution. Any attempt to sell, exchange, transfer, assign, pledge, encumber or otherwise dispose of or hypothecate in any way any of the Restricted Stock, or the levy of any execution, attachment or similar legal process upon the Restricted Stock, contrary to the terms and provisions of this Agreement, the Certificate and/or the Plan, shall be null and void and without legal force or effect.

7.Governing Law. All questions concerning the construction, validity and interpretation of this Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to the choice of law principles thereof.

8.Withholding of Tax. The Company shall have the power and the right to deduct or withhold, or require the Participant to remit to the Company, an amount sufficient to satisfy any federal, state, local and foreign taxes of any kind (including, but not limited to, the Participant’s FICA and SDI obligations) which the Company, in its sole discretion, deems necessary to be withheld or remitted to comply with the Code and/or any other applicable law, rule or regulation with respect to the Restricted Stock and, if the Participant fails to do so, the Company may otherwise refuse to issue or transfer any shares of Common Stock otherwise required to be issued pursuant to this Agreement and the Certificate. Any minimum statutorily required withholding obligation with regard to the Participant may be satisfied by reducing the amount of cash or shares of Common Stock otherwise deliverable to the Participant hereunder.

9.Section 83(b). If the Participant properly elects (as required by Section 83(b) of the Code) within 30 days after the issuance of the Restricted Stock to include in gross income for federal income tax purposes in the year of issuance the Fair Market Value of such shares of Restricted Stock, the Participant shall pay to the Company or make arrangements satisfactory to the Company to pay to the Company upon such election, any federal, state or local taxes required to be withheld with respect to the Restricted Stock. If the Participant shall

3

fail to make such payment, the Company shall, to the extent permitted by law, have the right to deduct from any payment of any kind otherwise due to the Participant any federal, state or local taxes of any kind required by law to be withheld with respect to the Restricted Stock, as well as the rights set forth in Section 8 hereof. The Participant acknowledges that it is the Participant’s sole responsibility, and not the Company’s, to file timely and properly the election under Section 83(b) of the Code and any corresponding provisions of state tax laws if the Participant elects to make such election, and the Participant agrees to timely provide the Company with a copy of any such election.

10.Legend. All certificates representing the Restricted Stock shall have endorsed thereon the legend set forth in Section 7.2(c) of the Plan. Notwithstanding the foregoing, in no event shall the Company be obligated to deliver to the Participant a certificate representing the Restricted Stock prior to the vesting dates set forth above.

11.Securities Representations. The shares of Restricted Stock are being issued to the Participant and this Agreement is being made by the Company in reliance upon the following express representations and warranties of the Participant. The Participant acknowledges, represents and warrants that:

(a)The Participant has been advised that the Participant may be an “affiliate” within the meaning of Rule 144 under the Securities Act and in this connection the Company is relying in part on the Participant’s representations set forth in this Section 11.

(b)If the Participant is deemed an affiliate within the meaning of Rule 144 of the Securities Act, the shares of Restricted Stock must be held indefinitely unless an exemption from any applicable resale restrictions is available or the Company files an additional registration statement (or a “re-offer prospectus”) with regard to the shares of Restricted Stock and the Company is under no obligation to register the shares of Restricted Stock (or to file a “re-offer prospectus”).

(c)If the Participant is deemed an affiliate within the meaning of Rule 144 of the Securities Act, the Participant understands that (i) the exemption from registration under Rule 144 will not be available unless (A) a public trading market then exists for the Common Stock of the Company, (B) adequate information concerning the Company is then available to the public, and (C) other terms and conditions of Rule 144 or any exemption therefrom are complied with, and (ii) any sale of the shares of vested Restricted Stock hereunder may be made only in limited amounts in accordance with the terms and conditions of Rule 144 or any exemption therefrom.

12.Entire Agreement; Amendment. This Agreement, together with the Plan and the Certificate, contains the entire agreement between the parties hereto with respect to the subject matter contained herein, and supersedes all prior agreements or prior understandings, whether written or oral, between the parties relating to such subject matter; provided that to the extent the Participant is party to an effective employment agreement with the Company, the terms set forth therein shall govern in the event of a conflict with Section 3 of this Agreement. The Committee shall have the right, in its sole discretion, to modify or amend this Agreement and/or the Certificate from time to time in accordance with and as provided in the Plan. This Agreement may also be modified or amended by a writing signed by both the Company and the Participant. The Company shall give written notice to the Participant of any such modification or amendment of this Agreement or the Certificate as soon as practicable after the adoption thereof.

13.Notices.Any notice hereunder by the Participant shall be given to the Company in writing and such notice shall be deemed duly given only upon receipt thereof by the General Counsel of the Company. Any notice hereunder by the Company shall be given to the Participant in writing and such notice shall be deemed duly given only upon receipt thereof at such address as the Participant may have on file with the Company.

4

14.Acceptance. The Participant shall be deemed to accept this Agreement unless the Participant provides the Company with written notice to the contrary prior to the expiration of the 60-day period following the Grant Date, in which case, the Participant shall forfeit the Restricted Stock

15.No Right to Employment. Any questions as to whether and when there has been a Termination and the cause of such Termination shall be determined in the sole discretion of the Committee. Nothing in this Agreement shall interfere with or limit in any way the right of the Company, its Subsidiaries or Affiliates to terminate the Participant’s employment or service at any time, for any reason and with or without Cause.

16.Transfer of Personal Data. The Participant authorizes, agrees and unambiguously consents to the transmission by the Company (or any Subsidiary) of any personal data information related to the Restricted Stock awarded under this Agreement for legitimate business purposes (including, without limitation, the administration of the Plan). This authorization and consent is freely given by the Participant.

17.Compliance with Laws. The issuance of the Restricted Stock or unrestricted shares pursuant to this Agreement shall be subject to, and shall comply with, any applicable requirements of any foreign and U.S. federal and state securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act, the Exchange Act and in each case any respective rules and regulations promulgated thereunder) and any other law or regulation applicable thereto. The Company shall not be obligated to issue the Restricted Stock or any of the shares pursuant to this Agreement if any such issuance would violate any such requirements.

18.Section 409A. Notwithstanding anything herein or in the Plan to the contrary, the shares of Restricted Stock are intended to be exempt from the applicable requirements of Section 409A of the Code and shall be limited, construed and interpreted in accordance with such intent.

19.Binding Agreement; Assignment. This Agreement and the Certificate shall inure to the benefit of, be binding upon, and be enforceable by the Company and its successors and assigns. The Participant shall not assign (except in accordance with Section 6 hereof) any part of this Agreement and the Certificate without the prior express written consent of the Company.

20.Headings. The titles and headings of the various sections of this Agreement have been inserted for convenience of reference only and shall not be deemed to be a part of this Agreement.

21.Further Assurances. Each party hereto shall do and perform (or shall cause to be done and performed) all such further acts and shall execute and deliver all such other agreements, certificates, instruments and documents as either party hereto reasonably may request in order to carry out the intent and accomplish the purposes of this Agreement and the Plan and the consummation of the transactions contemplated thereunder.

22.Severability. The invalidity or unenforceability of any provisions of this Agreement in any jurisdiction shall not affect the validity, legality or enforceability of the remainder of this Agreement in such jurisdiction or the validity, legality or enforceability of any provision of this Agreement in any other jurisdiction, it being intended that all rights and obligations of the parties hereunder shall be enforceable to the fullest extent permitted by law.

23.Acquired Rights. The Participant acknowledges and agrees that: (a) the Company may terminate or amend the Plan at any time; (b) the award of Restricted Stock made under this Agreement is completely independent of any other award or grant and is made at the sole discretion of the Company; (c) no past grants or awards (including, without limitation, the Restricted Stock awarded hereunder) give the Participant any right to any grants or awards in the future whatsoever; and (d) any benefits granted under this Agreement

5

are not part of the Participant’s ordinary salary and shall not be considered as part of such salary in the event of severance, redundancy or resignation.

[Remainder of Page Intentionally Left Blank]

6

IN WITNESS WHEREOF, the Company has issued the Restricted Stock to the Participant as of the date first written above.

SANDRIDGE ENERGY, INC.

By:

Name:    James D. Bennett            

Title:    President & Chief Executive Officer    

7

EX-10.1.5

Exhibit 10.1.5

	SandRidge Energy, Inc.
	123 Robert S. Kerr Avenue
	Oklahoma City, Oklahoma73102

Performance Share Unit Award Certificate and Agreement

Name:	[●]	Award Number:	[●]
Address:	[●]	Plan:	2016 Omnibus Incentive Plan
		Employee ID:	[●]

Effective [GRANT DATE] (the “Grant Date”), you have been granted an Award of [NUMBER OF UNITS GRANTED] SandRidge Energy, Inc. (the “Company”) performance share units, subject to the following requirements and characteristics:

Target Allocation: [NUMBER OF UNITS GRANTED]

Performance Period: [●]

Time-based Condition (Vesting Period): [●]

Performance Conditions: [●]

Maximum Units Awardable: [●]

Settlement Method: [●]

This Award is granted under and governed by the terms and conditions of the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan and the Performance Share Unit Award Agreement. A copy of the Plan can be found under the Department – People & Culture tab of the Company’s intranet.

PERFORMANCE SHARE UNIT AWARD AGREEMENT

PURSUANT TO THE

SANDRIDGE ENERGY, INC. 2016 OMNIBUS INCENTIVE PLAN

THIS PERFORMANCE UNIT AWARD AGREEMENT (this “Agreement”), dated as of the Grant Date specified in the Performance Share Unit Award Certificate attached hereto (the “Certificate”), is entered into by and between SandRidge Energy, Inc., a corporation organized in the State of Delaware (the “Company”), and the Participant specified above, pursuant to the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, as in effect and as amended from time to time (the “Plan”), which is administered by the Committee; and

WHEREAS, it has been determined under the Plan that it would be in the best interests of the Company to grant the Performance Share Units (“PSUs”) detailed in the Certificate to the Participant.

NOW, THEREFORE, in consideration of the mutual covenants and promises hereinafter set forth and for other good and valuable consideration, the parties hereto hereby mutually covenant and agree as follows:

1.Incorporation By Reference; Plan Document Receipt. This Agreement and the Certificate are subject in all respects to the terms and provisions of the Plan (including, without limitation, any amendments thereto adopted at any time and from time to time, unless such amendments are (a) expressly intended not to apply to the Award provided hereunder or (b) impair the Participant’s rights with respect to this Award without the consent of the Participant), all of which terms and provisions are made a part of and incorporated in this Agreement as if they were each expressly set forth herein. Except as provided otherwise herein, any capitalized term not defined in this Agreement shall have the same meaning as is ascribed thereto in the Plan or the Certificate. The Participant hereby acknowledges receipt of a true copy of the Plan and that the Participant has read the Plan carefully and fully understands its content. In the event of any conflict between the terms of this Agreement and the terms of the Plan, the terms of the Plan shall control.

2.Grant of Performance Unit Award. The Company hereby grants to the Participant, as of the Grant Date, the total number of PSUs specified above, each of which has the Target Value specified above, with the actual value to be paid out per PSU pursuant to this Award contingent upon satisfaction of the vesting conditions described in Section 3 hereof, subject to Section 4, but not to exceed the Maximum Value.

3.Vesting.

(a)The PSUs subject to this Award shall be subject to both a time-based vesting condition (the “Time-Based Condition”) and a performance-based vesting condition (the “Performance Condition”), as detailed in the Certificate. Except as expressly provided herein, none of the PSUs shall be “vested” for purposes of this Agreement, unless and until both the Time-Based Condition and the Performance Condition for such PSUs are satisfied and subject to the Participant’s continued service with the Company or any of its subsidiaries at such time.

(b)Change in Control.For the avoidance of doubt, (i) a Change in Control shall result in 100% accelerated vesting of the PSUs at the target allocation as detailed in the Certificate, and (ii) in connection with a Change in Control or any other event described in Section 4.2 of the Plan, the Committee shall have the discretion to adjust the PSUs and the Performance Condition as provided in the Plan.

(c)Forfeiture. All PSUs for which the Time-Based Condition has not been satisfied prior to a Participant’s Termination for any reason shall be immediately forfeited upon such Termination and the Participant shall have no further rights to such PSUs hereunder. Any PSUs that do not attain threshold level of performance as of the end of the applicable Performance Period shall expire immediately following the date that the Committee determines the level at which the Performance Conditions are satisfied.

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4.Payment. Following the satisfaction of both the Time-Based Condition and the Performance Condition with respect to a PSU granted hereunder, the Participant shall receive consideration in accordance with the Settlement Method detailed in the Certificate within thirty (30) days of the Committee’s certification of the extent to which the Performance Conditions for the applicable Performance Period have been met.

5.Non-Transferability. No PSU may be sold, assigned, transferred, encumbered, hypothecated or pledged by the Participant, other than to the Company as a result of forfeiture of the PSUs as provided herein.

6.Governing Law. All questions concerning the construction, validity and interpretation of this Agreement shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to the choice of law principles thereof.

7.Withholding of Tax. The Participant agrees and acknowledges that the Company shall deduct or withhold from the consideration due with respect to the vesting of the PSUs an amount sufficient to satisfy any federal, state, local and foreign taxes of any kind (including, but not limited to, the Participant’s FICA and SDI obligations) which the Company, in its sole discretion, deems necessary to be withheld or remitted to comply with the Code and/or any other applicable law, rule or regulation with respect to the PSUs.

8.Entire Agreement; Amendment. This Agreement, together with the Plan and the Certificate, contains the entire agreement between the parties hereto with respect to the subject matter contained herein, and supersedes all prior agreements or prior understandings, whether written or oral, between the parties relating to such subject matter; provided that to the extent the Participant is party to an effective employment agreement with the Company, the terms set forth therein applicable to equity awards shall govern in the event of a conflict with Section 3 of this Agreement. The Committee shall have the right, in its sole discretion, to modify or amend this Agreement and/or the Certificate from time to time in accordance with and as provided in the Plan. This Agreement may also be modified or amended by a writing signed by both the Company and the Participant. The Company shall give written notice to the Participant of any such modification or amendment of this Agreement or the Certificate as soon as practicable after the adoption thereof.

9.Notices. Any notice hereunder by the Participant shall be given to the Company in writing and such notice shall be deemed duly given only upon receipt thereof by the General Counsel of the Company. Any notice hereunder by the Company shall be given to the Participant in writing and such notice shall be deemed duly given only upon receipt thereof at such address as the Participant may have on file with the Company.

10.No Right to Employment. Any questions as to whether and when there has been a Termination and the cause of such Termination shall be determined in the sole discretion of the Committee. Nothing in this Agreement shall interfere with or limit in any way the right of the Company, its Subsidiaries or its Affiliates to terminate the Participant’s employment or service at any time, for any reason and with or without Cause.

11.Transfer of Personal Data. The Participant authorizes, agrees and unambiguously consents to the transmission by the Company (or any Subsidiary) of any personal data information related to the PSUs awarded under this Agreement for legitimate business purposes. This authorization and consent is freely given by the Participant.

12.Compliance with Laws. The grant of PSUs hereunder shall be subject to, and shall comply with, any applicable requirements of any foreign and U.S. federal and state securities laws, rules and regulations (including, without limitation, the provisions of the Securities Act, the Exchange Act and in each case any respective rules and regulations promulgated thereunder) and any other law, rule regulation or exchange requirement applicable thereto. The Company shall not be obligated to issue the PSUs or pay any amounts due pursuant to this Agreement if any such issuance or payment would violate any such requirements. As a condition to the settlement of the PSUs, the Company may require the Participant to satisfy any qualifications that may be necessary or appropriate to evidence compliance with any applicable law or regulation.

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13.Section 409A. Notwithstanding anything herein or in the Plan to the contrary, the PSUs are intended to be exempt from the applicable requirements of Section 409A of the Code and shall be limited, construed and interpreted in accordance with such intent as is reasonable under the circumstances.

14.Binding Agreement; Assignment. This Agreement and the Certificate shall inure to the benefit of, be binding upon, and be enforceable by the Company and its successors and assigns. The Participant shall not assign any part of this Agreement and the Certificate without the prior express written consent of the Company.

15.Headings. The titles and headings of the various sections of this Agreement have been inserted for convenience of reference only and shall not be deemed to be a part of this Agreement.

16.Further Assurances. Each party hereto shall do and perform (or shall cause to be done and performed) all such further acts and shall execute and deliver all such other agreements, certificates, instruments and documents as either party hereto reasonably may request in order to carry out the intent and accomplish the purposes of this Agreement and the Plan and the consummation of the transactions contemplated thereunder.

17.Severability. The invalidity or unenforceability of any provisions of this Agreement in any jurisdiction shall not affect the validity, legality or enforceability of the remainder of this Agreement in such jurisdiction or the validity, legality or enforceability of any provision of this Agreement in any other jurisdiction, it being intended that all rights and obligations of the parties hereunder shall be enforceable to the fullest extent permitted by law.

18.Acquired Rights. The Participant acknowledges and agrees that: (a) the Company may terminate or amend the Plan at any time; (b) the Award of PSUs made under this Agreement is completely independent of any other award or grant and is made at the sole discretion of the Company; (c) no past grants or awards (including, without limitation, the PSUs awarded hereunder) give the Participant any right to any grants or awards in the future whatsoever; and (d) any benefits granted under this Agreement are not part of the Participant’s ordinary salary, and shall not be considered as part of such salary in the event of severance, redundancy or resignation.

* * * * *

    4

IN WITNESS WHEREOF, the Company has issued the Performance Units to the Participant pursuant to this Agreement as of the date first written above.

SANDRIDGE ENERGY, INC.

By:

Name:    James D. Bennett            

Title:    President & Chief Executive Officer    

Signature Page to Performance Unit Award Agreement

EX-10.9.1

Exhibit 10.9.1

AMENDMENT NO. 1 TO PROMISSORY NOTE

THIS AMENDMENT NO. 1 TO PROMISSORY NOTE (this “Amendment”) is entered into as of January 27, 2017, by and among SandRidge Realty, LLC, an Oklahoma limited liability company (“Borrower”), Fir Tree E&P Holdings II, LLC, a Delaware limited liability company (“Fir Tree”), and SOLA LTD, a Cayman Islands exempted company (“Solus”; and together with Fir Tree and certain other co-lenders from time to time, together with their successors and assigns, collectively, “Lender”).

BACKGROUND

WHEREAS, reference is made to that certain Promissory Note, dated as of October 4, 2016, executed by Borrower and payable to Lender (the “Note”);

WHEREAS, Borrower and Lender have agreed to modify the Note on the terms and conditions set forth herein;

NOW, THEREFORE, the parties hereto hereby agree as follows:

1.    Definitions. All capitalized terms not otherwise defined herein shall have the meanings given to them in the Note.

2.    Amendments.

(a) Section 8 of the Note is hereby amended and restated as follows:

“This Note shall not be prepayable except upon Lender’s prior written consent or as provided in Section 5 above. Notwithstanding the foregoing, commencing on the earlier of the date on which (i) all of the Indebtedness and other sums owing and/or payable under the First Lien Credit Agreement and/or the other First Lien Credit Documents have been paid in full and no re-borrowing or further credit is available thereunder, and all commitments thereunder have been cancelled, or (ii) the First Lien Credit Agreement has been refinanced, Borrower may prepay this Note in whole or in part at any time, at par, and from time to time during the term hereof upon ten (10) days’ prior written notice to Lender, without any prepayment premium or penalty, subject to the application of payments provisions set forth in Section 6 above.”

3.    Governing Law. THIS AMENDMENT WAS NEGOTIATED, EXECUTED AND DELIVERED IN THE STATE OF NEW YORK, IN ALL RESPECTS, INCLUDING, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, MATTERS OF CONSTRUCTION, VALIDITY AND PERFORMANCE, AND THIS NOTE AND THE OBLIGATIONS ARISING HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK APPLICABLE TO CONTRACTS MADE AND PERFORMED IN SUCH STATE (WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS). TO THE FULLEST EXTENT PERMITTED BY LAW, BORROWER HEREBY UNCONDITIONALLY AND IRREVOCABLY WAIVES ANY RIGHT TO ASSERT THAT THE LAW OF ANY OTHER JURISDICTION GOVERNS THIS AMENDMENT, AND THIS

1

AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

4.    Headings. Section headings in this Amendment are included herein for convenience of reference only and shall not constitute a part of this Amendment for any other purpose.

5.    Counterparts; Facsimile. This Amendment may be executed by the parties hereto in one or more counterparts (including by facsimile transmission or in portable document format (PDF)), each of which shall be deemed an original and all of which when taken together shall constitute one and the same agreement.

6.    References. Any reference to the Note contained in any notice, request, certificate or other document executed concurrently with or after the execution and delivery of this Amendment shall be deemed to include this Amendment unless the context shall otherwise require.

7.    Other Provisions. All other provisions of the Note not specifically amended by this Amendment shall remain in full force and effect.

[Signature Page Follows.]

2

IN WITNESS WHEREOF, this Amendment has been duly executed as of the day and year first written above.

BORROWER:

SANDRIDGE REALTY LLC,

an Oklahoma limited liability company
By: /s/ Julian Bott
Name:    Julian Bott    
Title:    Executive Vice President and Chief

Financial Officer

LENDER:

FIR TREE E&P HOLDINGS II, LLC,

a Delaware limited liability company
By:    /s/ Brian Meyer    
Name:    Brian Meyer    
Title:    Authorized Person    

SOLA LTD,

a Cayman Islands exempted company
By:    /s/ Joshua Sock        
Name:    Joshua Sock    
Title:    Authorized Signatory    

EX-21.1

Exhibit 21.1

SANDRIDGE ENERGY, INC. SUBSIDIARIES

Entity Name	State of Organization
Integra Energy, L.L.C.	Texas
Lariat Services, Inc.	Texas
SandRidge Exploration and Production, LLC	Delaware
SandRidge Holdings, Inc.	Delaware
SandRidge Midstream, Inc.	Texas
SandRidge Operating Company	Texas
SandRidge Realty, LLC	Oklahoma

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-214383) of SandRidge Energy, Inc., of our report dated March 3, 2017 relating to the consolidated financial statements, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

March 3, 2017

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use by SandRidge Energy, Inc. (the “Company”), of our name and to the inclusion of information taken from the reports listed below in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, including any amendments thereto, filed with the U.S. Securities and Exchange Commission on or about March 3, 2017, as well as to the incorporation by reference thereof into the Company’s Registration Statement on Form S-8 (File No. 333-214383):

December 31, 2016, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2015, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2014, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

CAWLEY, GILLESPIE & ASSOCIATES, INC.

J. Zane Meekins                

Executive Vice President

Fort Worth, Texas

March 3, 2017

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use by SandRidge Energy, Inc. (the “Company”), of our name and to the inclusion of information taken from the reports listed below in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the U.S. Securities and Exchange Commission on or about March 3, 2017, as well as to the incorporation by reference thereof into the Company’s Registration Statement on Form S-8 (File No. 333-214383):

December 31, 2016, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2015, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2014, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:    /s/ C.H. (Scott) Rees III, P.E.    

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

Dallas, Texas

March 3, 2017

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-23.4

Exhibit 23.4

	621 SEVENTEENTH STREET, SUITE 1550	DENVER, COLORADO 80293	(303) 623-9147

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use by SandRidge Energy, Inc. (the “Company”), of our name and to the inclusion of information taken from the reports listed below in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, filed with the U.S. Securities and Exchange Commission on or about March 3, 2017, as well as to the incorporation by reference thereof into the Company’s Registration Statement on Form S-8 (File No. 333-214383):

December 31, 2016, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2015, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

RYDER SCOTT COMPANY, L.P.

Denver, Colorado

March 3, 2017

1100 LOUISIANA, SUITE 4600    HOUSTON, TEXAS 77002-5218    TEL (713) 651-9191    FAX (713) 651-0849

1015 4^TH STREET S.W. SUITE 600    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

EX-31.1

Exhibit 31.1

Certification of the Company’s Chief Executive Officer Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, James D. Bennett, certify that:

1. I have reviewed this annual report on Form 10-K of SandRidge Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ James D. Bennett

James D. Bennett

President and Chief Executive Officer

Date: March 3, 2017

EX-31.2

Exhibit 31.2

Certification of the Company’s Chief Financial Officer Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, Julian Bott, certify that:

1. I have reviewed this annual report on Form 10-K of SandRidge Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Julian Bott

Julian Bott

Executive Vice President and Chief Financial Officer

Date: March 3, 2017

EX-32.1

Exhibit 32.1

Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

Pursuant to 18 U.S.C. § 1350, the undersigned officers of SandRidge Energy, Inc. (the “Company”), hereby certify that the Company’s Annual Report on Form 10-K for the year ended December 31, 2016 (the “Report”), fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ James D. Bennett

James D. Bennett

President and Chief Executive Officer

March 3, 2017

/s/ Julian Bott

Julian Bott

Executive Vice President and Chief Financial Officer

March 3, 2017

EX-99.1

Exhibit 99.1

February 8, 2017

Mr. Lance J. Galvin

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma 73102

Re:	Evaluation Summary
	SandRidge Energy, Inc. Interests
	Proved Reserves
	As of January 1, 2017

Dear Mr. Galvin:

As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the SandRidge Energy, Inc. (“SandRidge”) interests in certain oil and gas properties located in Kansas and Oklahoma. The net reserves and future net revenue for SandRidge have been estimated using the proportional consolidation method with respect to the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II. Under the proportional consolidation method and for the properties in which the Trusts have an interest, SandRidge’s interest share of revenues, expenses, investments and liabilities includes both Sandridge’s direct interest in the properties and SandRidge’s revenue interest share of the Trusts. It is our understanding that the proved reserves estimated in this report constitute approximately 72 percent of all proved reserves owned by SandRidge. This report, completed on February 8, 2017, has been prepared for use in filings with the U.S. Securities and Exchange Commission by SandRidge.

Composite reserve estimates and economic forecasts for the proved reserves to the SandRidge proportional consolidation interests are summarized below:

		Proved	Proved
		Developed	Developed	Proved
		Producing	Non-Producing	Undeveloped	Proved
Net Reserves
Oil/Condensate	- Mbbl	15,735	239	3,137	19,111
Gas	- MMcf	363,204	4,907	41,249	409,359
NGL	- Mbbl	27,098	96	3,482	30,676
Revenue
Oil/Condensate	- M$	638,045	9,702	127,206	774,952
Gas	- M$	572,683	7,661	65,496	645,841
NGL	- Mbbl	296,301	1,043	38,127	335,471
Operating Income (BFIT)	- M$	630,381	9,986	77,385	717,752
Discounted @ 10%	- M$	383,287	6,156	21,726	411,169

Evaluation Summary

SandRidge Energy, Inc.

Page 2

In accordance with the Securities and Exchange Commission guidelines, the operating income (BFIT) has been discounted at an annual rate of 10% to determine its “present worth”. The discounted value, “present worth”, shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc. For the properties in which the Trusts have an interest, SandRidge is obligated to act as a reasonably prudent operator by disregarding the existence of the Trusts’ royalty interests as burdens affecting the properties. Therefore, the economic viability of these properties has been evaluated based on economic limits when combining the SandRidge direct interest and the Trusts’ total royalty interest.

    The annual average Henry Hub spot market gas price of $2.481 per MMBtu and the annual average WTI Cushing spot oil price of $42.75 per barrel were used in this report. In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2016. The oil and gas prices were held constant and were adjusted for gravity, heating value, quality, transportation and regional price differentials. The adjusted volume-weighted average product prices over the life of the properties are $40.55 per barrel of oil, $10.94 per barrel of NGL and $1.58 per Mcf of gas.

Operating costs were based on operating expense records of SandRidge. For non-operated properties, these costs include the overhead expenses allowed under existing joint operating agreements. Drilling and completion costs were based on estimates provided by SandRidge and reviewed for reasonableness by Cawley, Gillespie & Associates. Abandonment costs used in the report are estimates prepared by SandRidge to abandon the wells and production facilities, net of salvage value. As per the Securities and Exchange Commission guidelines, neither expenses nor investments were escalated.

The proved reserve classifications conform to criteria of the Securities and Exchange Commission as defined in pages 2-3 of the Appendix. The estimates of reserves in this report have been prepared in accordance with the definitions and disclosure guidelines set forth in the Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the date of this report as noted herein. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geoscience. Therefore, the possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered.

The reserves were estimated using a combination of the production performance, volumetric and analogy methods, in each case as we considered to be appropriate and necessary to establish the conclusions set forth herein. The methods employed in estimating reserves are described in page 1 of the Appendix. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

Evaluation Summary

SandRidge Energy, Inc.

Page 3

The reserve estimates were based on interpretations of factual data furnished by SandRidge. Ownership interests were supplied by SandRidge and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

Cawley, Gillespie & Associates, Inc. is independent with respect to SandRidge as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers (“SPE Standards”). Neither Cawley, Gillespie & Associates, Inc. nor any of its employees has any interest in the subject properties. Neither the employment to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties.

Our work-papers and related data are available for inspection and review by authorized parties. The technical person responsible for the preparation of this report meets or exceeds the education, training, and experience requirements set forth in the SPE Standards.

Respectfully submitted,

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Texas Registered Engineering Firm F-693

JZM:ptn

APPENDIX

Methods Employed in the Estimation of Reserves

The four methods customarily employed in the estimation of reserves are (1) productionperformance, (2) materialbalance, (3) volumetric and (4) analogy. Most estimates, although based primarily on one method, utilize other methods depending on the nature and extent of the data available and the characteristics of the reservoirs.

Basic information includes production, pressure, geological and laboratory data. However, a large variation exists in the quality, quantity and types of information available on individual properties. Operators are generally required by regulatory authorities to file monthly production reports and may be required to measure and report periodically such data as well pressures, gas-oil ratios, well tests, etc. As a general rule, an operator has complete discretion in obtaining and/or making available geological and engineering data. The resulting lack of uniformity in data renders impossible the application of identical methods to all properties, and may result in significant differences in the accuracy and reliability of estimates.

A brief discussion of each method, its basis, data requirements, applicability and generalization as to its relative degree of accuracy follows:

Production performance. This method employs graphical analyses of production data on the premise that all factors which have controlled the performance to date will continue to control and that historical trends can be extrapolated to predict future performance. The only information required is production history. Capacity production can usually be analyzed from graphs of rates versus time or cumulative production. This procedure is referred to as "decline curve" analysis. Both capacity and restricted production can, in some cases, be analyzed from graphs of producing rate relationships of the various production components. Reserve estimates obtained by this method are generally considered to have a relatively high degree of accuracy with the degree of accuracy increasing as production history accumulates.

Material balance. This method employs the analysis of the relationship of production and pressure performance on the premise that the reservoir volume and its initial hydrocarbon content are fixed and that this initial hydrocarbon volume and recoveries therefrom can be estimated by analyzing changes in pressure with respect to production relationships. This method requires reliable pressure and temperature data, production data, fluid analyses and knowledge of the nature of the reservoir. The material balance method is applicable to all reservoirs, but the time and expense required for its use is dependent on the nature of the reservoir and its fluids. Reserves for depletion type reservoirs can be estimated from graphs of pressures corrected for compressibility versus cumulative production, requiring only data that are usually available. Estimates for other reservoir types require extensive data and involve complex calculations most suited to computer models which makes this method generally applicable only to reservoirs where there is economic justification for its use. Reserve estimates obtained by this method are generally considered to have a degree of accuracy that is directly related to the complexity of the reservoir and the quality and quantity of data available.

Volumetric. This method employs analyses of physical measurements of rock and fluid properties to calculate the volume of hydrocarbons in-place. The data required are well information sufficient to determine reservoir subsurface datum, thickness, storage volume, fluid content and location. The volumetric method is most applicable to reservoirs which are not susceptible to analysis by production performance or material balance methods. These are most commonly newly developed and/or no-pressure depleting reservoirs. The amount of hydrocarbons in-place that can be recovered is not an integral part of the volumetric calculations but is an estimate inferred by other methods and a knowledge of the nature of the reservoir. Reserve estimates obtained by this method are generally considered to have a low degree of accuracy; but the degree of accuracy can be relatively high where rock quality and subsurface control is good and the nature of the reservoir is uncomplicated.

Analogy. This method which employs experience and judgment to estimate reserves, is based on observations of similar situations and includes consideration of theoretical performance. The analogy method is applicable where the data are insufficient or so inconclusive that reliable reserve estimates cannot be made by other methods. Reserve estimates obtained by this method are generally considered to have a relatively low degree of accuracy.

Much of the information used in the estimation of reserves is itself arrived at by the use of estimates. These estimates are subject to continuing change as additional information becomes available. Reserve estimates which presently appear to be correct may be found to contain substantial errors as time passes and new information is obtained about well and reservoir performance.

Appendix

Cawley, Gillespie & Associates, Inc.Page 1

APPENDIX

Reserve Definitions and Classifications

The Securities and Exchange Commission, in SX Reg. 210.4-10 dated November 18, 1981, as amended on September 19, 1989 and January 1, 2010, requires adherence to the following definitions of oil and gas reserves:

"(22)    Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, 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 the 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.

"(i)    The area of a reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

"(ii)    In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

"(iii)    Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

"(iv)    Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

"(v)    Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

"(6)    Developed oil and gas reserves. Developed oil and gas reserves are 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.

"(31)    Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are 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 recompletion.

“(i)    Reserves on undrilled acreage shall be 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 can be 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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

Appendix

Cawley, Gillespie & Associates, Inc.Page 2

"(18)    Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

“(i)    When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

“(ii)    Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

“(iii)    Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

“(iv)    See also guidelines in paragraphs (17)(iv) and (17)(vi) of this section (below).

"(17)    Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

“(i)    When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

“(ii)    Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

“(iii)    Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

“(iv)    The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

“(v)    Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

“(vi)    Pursuant to paragraph (22)(iii) of this section (above), where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.”

Instruction 4 of Item 2(b) of Securities and Exchange Commission Regulation S-K was revised January 1, 2010 to state that "a registrant engaged in oil and gas producing activities shall provide the information required by Subpart 1200 of Regulation S–K." This is relevant in that Instruction 2 to paragraph (a)(2) states: “The registrant is permitted, but not required, to disclose probable or possible reserves pursuant to paragraphs (a)(2)(iv) through (a)(2)(vii) of this Item.”

"(26)    Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given 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 gas or related substances to market, and all permits and financing required to implement the project.

“Note to paragraph (26): 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).”

Appendix

Cawley, Gillespie & Associates, Inc.Page 3

EX-99.2

Exhibit 99.2

February 2, 2017

Mr. Lance J. Galvin

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma 73102

Dear Mr. Galvin:

In accordance with your request, we have estimated the proved developed producing reserves and future revenue, as of December 31, 2016, to the SandRidge Energy, Inc. (SandRidge) proportional consolidation interest in certain oil and gas properties located in Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 4 percent of all proved reserves owned by SandRidge. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, except that future income taxes are excluded and, as requested, per-well overhead expenses are excluded for the operated properties. Definitions are presented immediately following this letter. This report has been prepared for SandRidge's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The net reserves and future net revenue to the SandRidge proportional consolidation interest have been estimated incorporating the terms of the SandRidge Permian Trust (Trust) prospectus using the proportional consolidation method. For the properties in which the Trust has an interest, SandRidge is obligated to act under the terms of the prospectus as a reasonably prudent operator by disregarding the existence of the Trust's royalty interests as burdens affecting such properties. Therefore, the economic viability of these properties has been evaluated based on economic limits when combining the SandRidge direct interest and the total Trust royalty interest. Under the proportional consolidation method, SandRidge's interest share of revenues, expenses, investments, and liabilities includes both SandRidge's direct interest in the properties and SandRidge's revenue interest share of the Trust.

We estimate the net reserves and future net revenue to the SandRidge proportional consolidation interest in these properties, as of December 31, 2016, to be:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	4,812.4	698.2	2,392.7	-59,961.7	-23,026.1

Note: The estimates herein are based on economic limits when combining the SandRidge direct interest and the Trust royalty interest. The negative future net revenues are the result of showing only the SandRidge proportional consolidation interest.

The oil volumes shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing reserves. No study was made to determine whether proved developed non-producing, proved undeveloped, probable, or possible reserves might be established

for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is SandRidge's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for SandRidge's share of production taxes, ad valorem taxes, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2016. For oil and NGL volumes, the average West Texas Intermediate (WTI) spot price of $42.75 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.481 per MMBTU is adjusted for energy content, transportation fees, and market differentials. As a reference, the average NYMEX WTI and NYMEX Henry Hub prices for the same time period were $42.75 per barrel and $2.551 per MMBTU, respectively. The adjusted product prices of $39.70 per barrel of oil, $14.11 per barrel of NGL, and $1.826 per MCF of gas are held constant throughout the lives of the properties.

Operating costs used in this report are based on operating expense records of SandRidge, the operator of the majority of the properties, and include only direct lease- and field-level costs. Operating costs have been divided into per-well costs and per-unit-of-production costs. As requested, these costs do not include the per-well overhead expenses allowed under joint operating agreements, nor do they include the headquarters general and administrative overhead expenses of SandRidge. Operating costs are not escalated for inflation.

Abandonment costs used in this report are SandRidge's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the SandRidge interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on SandRidge receiving its net revenue interest share of estimated future gross production. Additionally, we have been informed by SandRidge that it is not party to any firm transportation contracts for these properties.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by SandRidge, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well location maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from SandRidge and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Gregory S. Cohen, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:        

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

/s/ Gregory S. Cohen

By:

Gregory S. Cohen, P.E. 117412

Petroleum Engineer

Date Signed: February 2, 2017

GSC:CLM

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are 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.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and 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 and equip 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.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) 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 geologic barriers, or by both.

Definitions - Page 2 of 7

Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

Definitions - Page 3 of 7

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) 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. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating

Definitions - Page 4 of 7

costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, 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 the 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Definitions - Page 5 of 7

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given 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 gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): 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).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.    Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b.    Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.    Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b.    Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c.    Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d.    Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e.    Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f.    Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable

Definitions - Page 6 of 7

holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are 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 recompletion.

(i) Reserves on undrilled acreage shall be 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 can be 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.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

Ÿ    The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

Ÿ    The company's historical record at completing development of comparable long-term projects;

Ÿ    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

Ÿ    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

Ÿ    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(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, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7

EX-99.3

Exhibit 99.3

SandRidge Energy, Inc.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2016

/s/ Scott Wilson /seal/

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550    DENVER, COLORADO 80293    TELEPHONE (303) 623-9147

January 16, 2017

SandRidge Energy, Inc.

123 Robert S. Kerr

Oklahoma City, OK 73102

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of SandRidge Energy, Inc. (SandRidge) as of December 31, 2016. The subject properties are located in the state of Colorado. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 16, 2017 and presented herein, was prepared for public disclosure by SandRidge in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of SandRidge’s total net proved reserves as of December 31, 2016. Based on information provided by SandRidge, the third party estimate conducted by Ryder Scott addresses 50 percent of the total proved net oil reserves and 5 percent of the total proved net gas reserves of SandRidge. When put in discounted cash flow terms, the reserve values evaluated represent 12 percent of the FNI discounted at 10 percent.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2016, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

1100 LOUISIANA STREET, SUITE 4600    HOUSTON, TEXAS 77002-5294    TEL (713) 651-9191    FAX (713) 651-0849

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

SandRidge Energy, Inc.

January 16, 2017

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

SandRidge Energy, Inc.

As of December 31, 2016

	Proved
	Developed Producing		Undeveloped		Total Proved
Net Remaining Reserves
Oil/Condensate – MBarrels	3,238		22,986		26,224
Gas - MMCF	2,600		21,532		24,132
Income Data (M$)
Future Gross Revenue		$118,346		$837,726		$956,072
Deductions	31,391		563,324		594,715
Future Net Income (FNI)	$	86,955		$274,402		$361,357
Discounted FNI @ 10%	$	46,119	$	8,415	$	54,534

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of SandRidge and Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon proved reserves account for approximately 97 percent of total future gross revenue while gas reserves account for the remaining 3 percent of future revenue.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at five other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

SandRidge Energy, Inc.

January 16, 2017

Page 3

	Discounted Future Net Income (M$)
	As of December 31, 2016
Discount Rate		Total
Percent		Proved
9		$67,223
15		$11,874
20		$(10,761)
25		$(23,368)
30		$(30,458)

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At SandRidge’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

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January 16, 2017

Page 4

due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

SandRidge’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which SandRidge owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used individually or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

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January 16, 2017

Page 5

have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November 2016 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by SandRidge or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved undeveloped reserves included herein were estimated by analogy, the volumetric method, reservoir simulation, or a combination of methods. The volumetric analysis utilized pertinent well data furnished to Ryder Scott by SandRidge or which we have obtained from public data sources that were available through November 2016. The data utilized from the analogues in addition to well data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

SandRidge has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by SandRidge with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by SandRidge. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

SandRidge Energy, Inc.

January 16, 2017

Page 6

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by SandRidge. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

SandRidge furnished us with the above mentioned average prices in effect on December 31, 2016. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic areas included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

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January 16, 2017

Page 7

market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by SandRidge.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
United States	Oil	WTI Cushing	$42.75/BBL	$36.79/BBL
	Gas	Henry Hub	$2.49/MMBTU	$1.29/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished by SandRidge and include only those costs directly applicable to the leases or wells. The operating costs furnished were reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by SandRidge and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. SandRidge estimates that abandonment costs generally equal salvage values for the properties reviewed in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for SandRidge’s estimate. SandRidge uses a series of several cost entries spread over a period in which a well is drilled and completed to more accurately reflect cash flows. For this reason, wells that are spudded in one period may have lagging costs that spill over into the next period and some wells that are on production may show some final costs associated with site reclamation and other costs that may occur after production starts.

The proved undeveloped reserves in this report have been incorporated herein in accordance with SandRidge’s plans to develop these reserves as of December 31, 2016.  The implementation of SandRidge’s development plans as presented to us and incorporated herein is subject to the approval process adopted by SandRidge’s management.  As the result of our inquiries during the course of preparing this report, SandRidge has informed us that the development activities included herein have been subjected to and received the internal approvals required by SandRidge’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to SandRidge.   Additionally, SandRidge has informed us that they

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

SandRidge Energy, Inc.

January 16, 2017

Page 8

are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.  While these plans could change from those under existing economic conditions as of December 31, 2016, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by SandRidge were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to SandRidge. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by SandRidge.

SandRidge makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, SandRidge has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Forms S-3 and/or S-8 of SandRidge of the references to our name as well as to the references to our third party report for SandRidge, which appears

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

SandRidge Energy, Inc.

January 16, 2017

Page 9

in the December 31, 2016 annual report on Form 10-K of SandRidge. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by SandRidge.

We have provided SandRidge with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by SandRidge and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

/s/ Scott Wilson /seal/

Scott J. Wilson, P.E., MBA

Colorado License No. 36112

Senior Vice President

SJW (FWZ)/pl

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

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January 16, 2017

Page 1

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2000, is a Senior Vice President and Technical Advisor responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers, one published book chapter and another in SPEE monograph 4. He is the primary inventor on four US patents.

In addition to gaining experience and competency through prior work experience, several state Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills as part of his registration in four states. As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attends additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY ` PETROLEUM CONSULTANTS

XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Feb. 24, 2017	Jun. 30, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	SANDRIDGE ENERGY INC
Entity Central Index Key	0001349436
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Amendment Flag	false
Entity Public Float			$ 13.3
Entity Common Stock, Shares Outstanding		35,872,778

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Current assets
Cash and cash equivalents	$ 121,231
Restricted cash - collateral	50,000
Restricted cash - other	2,840
Accounts receivable, net	74,097
Derivative contracts	0
Prepaid expenses	5,375
Other current assets	3,633
Total current assets	257,176
Oil and natural gas properties, using full cost method of accounting
Proved (includes development and project costs excluded from amortization of $16.7 million and $34.6 million at December 31, 2016 and 2015, respectively)	840,201
Unproved	74,937
Less: accumulated depreciation, depletion and impairment	(353,030)
Net oil and natural gas properties capitalized costs	562,108
Other property, plant and equipment, net	255,824
Other assets	6,284
Total assets	1,081,392
Current liabilities
Accounts payable and accrued expenses	116,517
Derivative contracts	27,538
Asset retirement obligations	66,154
Other current liabilities	3,497
Total current liabilities	213,706
Long-term debt	305,308
Derivative contracts	2,176
Asset retirement obligations	40,327
Other long-term obligations	6,958
Total liabilities	568,475
Commitments and contingencies (Note 14)
SandRidge Energy, Inc. stockholders’ equity (deficit)
Common stock	20
Warrants	88,381
Additional paid-in capital	758,498
Additional paid-in capital - stockholder receivable	0
Treasury stock, at cost	0
Accumulated deficit	(333,982)
Total SandRidge Energy, Inc. stockholders’ equity (deficit)	512,917
Noncontrolling interest	0
Total stockholders’ equity (deficit)	512,917
Total liabilities and stockholders’ equity (deficit)	1,081,392
Successor | 8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015; aggregate liquidation preference of $265,000
SandRidge Energy, Inc. stockholders’ equity (deficit)
Preferred stock	0
Successor | 7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000
SandRidge Energy, Inc. stockholders’ equity (deficit)
Preferred stock	$ 0
Predecessor
Current assets
Cash and cash equivalents		$ 435,588
Restricted cash - collateral		0
Restricted cash - other		0
Accounts receivable, net		127,387
Derivative contracts		84,349
Prepaid expenses		6,833
Other current assets		19,931
Total current assets		674,088
Oil and natural gas properties, using full cost method of accounting
Proved (includes development and project costs excluded from amortization of $16.7 million and $34.6 million at December 31, 2016 and 2015, respectively)		12,529,681
Unproved		363,149
Less: accumulated depreciation, depletion and impairment		(11,149,888)
Net oil and natural gas properties capitalized costs		1,742,942
Other property, plant and equipment, net		491,760
Other assets		13,237
Total assets		2,922,027
Current liabilities
Accounts payable and accrued expenses		428,417
Derivative contracts		573
Asset retirement obligations		8,399
Other current liabilities		0
Total current liabilities		437,389
Long-term debt		3,562,378
Derivative contracts		0
Asset retirement obligations		95,179
Other long-term obligations		14,814
Total liabilities		4,109,760
Commitments and contingencies (Note 14)
SandRidge Energy, Inc. stockholders’ equity (deficit)
Common stock		630
Additional paid-in capital		5,301,136
Additional paid-in capital - stockholder receivable		(1,250)
Treasury stock, at cost		(5,742)
Accumulated deficit		(6,992,697)
Total SandRidge Energy, Inc. stockholders’ equity (deficit)		(1,697,917)
Noncontrolling interest		510,184
Total stockholders’ equity (deficit)		(1,187,733)
Total liabilities and stockholders’ equity (deficit)		2,922,027
Predecessor | 8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015; aggregate liquidation preference of $265,000
SandRidge Energy, Inc. stockholders’ equity (deficit)
Preferred stock		3
Predecessor | 7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000
SandRidge Energy, Inc. stockholders’ equity (deficit)
Preferred stock		$ 3

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015; aggregate liquidation preference of $265,000
Preferred stock, dividend rate, percentage		8.50%
7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000
Preferred stock, dividend rate, percentage		7.00%
Successor
Development and project costs excluded from amortization	$ 16,700
Preferred stock, par value (in dollars per share)	$ 0
Preferred stock, shares authorized (in shares)	0
Common stock, par value (in dollars per share)	$ 0.001
Common stock, shares authorized (in shares)	250,000,000
Common stock, issued (in shares)	19,635,000
Common stock, outstanding (in shares)	19,635,000
Successor | 8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015; aggregate liquidation preference of $265,000
Preferred stock, dividend rate, percentage	0.00%
Preferred stock, shares issued (in shares)	0
Preferred stock, shares outstanding (in shares)	0
Preferred stock, aggregate liquidation preference	$ 0
Successor | 7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000
Preferred stock, dividend rate, percentage	0.00%
Preferred stock, shares issued (in shares)	0
Preferred stock, shares outstanding (in shares)	0
Preferred stock, aggregate liquidation preference	$ 0
Predecessor
Development and project costs excluded from amortization		$ 34,600
Preferred stock, par value (in dollars per share)		$ 0.001
Preferred stock, shares authorized (in shares)		50,000,000
Common stock, par value (in dollars per share)		$ 0.001
Common stock, shares authorized (in shares)		1,800,000,000
Common stock, issued (in shares)		635,584,000
Common stock, outstanding (in shares)		633,471,000
Predecessor | 8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015; aggregate liquidation preference of $265,000
Preferred stock, dividend rate, percentage		8.50%
Preferred stock, shares issued (in shares)		2,650,000
Preferred stock, shares outstanding (in shares)		2,650,000
Preferred stock, aggregate liquidation preference		$ 265,000
Predecessor | 7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000
Preferred stock, dividend rate, percentage		7.00%
Preferred stock, shares issued (in shares)		2,770,000
Preferred stock, shares outstanding (in shares)		2,770,000
Preferred stock, aggregate liquidation preference		$ 277,000

XML

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Revenues
Oil, natural gas and NGL	$ 98,307
Other	149
Total revenues	98,456
Expenses
Production	24,997
Production taxes	2,643
Depreciation and depletion—oil and natural gas	33,971
Depreciation and amortization—other	3,922
Accretion of asset retirement obligations	2,090
Impairment	319,087
General and administrative	9,837
Employee termination benefits	12,334
Loss (gain) on derivative contracts	25,652
Loss on settlement of contract	0
Other operating expenses	268
Total expenses	434,801
(Loss) income from operations	(336,345)
Other (expense) income
Interest expense	(372)
Gain on extinguishment of debt	0
Gain on reorganization items, net	0
Other income, net	2,744
Total other income (expense)	2,372
(Loss) income before income taxes	(333,973)
Income tax expense (benefit)	9
Net (loss) income	(333,982)
Less: net (loss) income attributable to noncontrolling interest	0
Net (loss) income attributable to SandRidge Energy, Inc.	(333,982)
Preferred stock dividends	0
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$ (333,982)
(Loss) earnings per share
Basic (in dollars per share)	$ (17.61)
Diluted (in dollars per share)	$ (17.61)
Weighted average number of common shares outstanding
Basic (in shares)	18,967
Diluted (in shares)	18,967
Predecessor
Revenues
Oil, natural gas and NGL		$ 279,971	$ 707,434	$ 1,420,879
Other		13,838	61,275	137,879
Total revenues		293,809	768,709	1,558,758
Expenses
Production		129,608	308,701	346,088
Production taxes		6,107	15,440	31,731
Depreciation and depletion—oil and natural gas		86,613	319,913	434,295
Depreciation and amortization—other		21,323	47,382	59,636
Accretion of asset retirement obligations		4,365	4,477	9,092
Impairment		718,194	4,534,689	192,768
General and administrative		116,091	137,715	113,991
Employee termination benefits		18,356	12,451	8,874
Loss (gain) on derivative contracts		4,823	(73,061)	(334,011)
Loss on settlement of contract		90,184	50,976	0
Other operating expenses		4,348	52,704	106,070
Total expenses		1,200,012	5,411,387	968,534
(Loss) income from operations		(906,203)	(4,642,678)	590,224
Other (expense) income
Interest expense		(126,099)	(321,421)	(244,109)
Gain on extinguishment of debt		41,179	641,131	0
Gain on reorganization items, net		2,430,599	0	0
Other income, net		1,332	2,040	3,490
Total other income (expense)		2,347,011	321,750	(240,619)
(Loss) income before income taxes		1,440,808	(4,320,928)	349,605
Income tax expense (benefit)		11	123	(2,293)
Net (loss) income		1,440,797	(4,321,051)	351,898
Less: net (loss) income attributable to noncontrolling interest		0	(623,506)	98,613
Net (loss) income attributable to SandRidge Energy, Inc.		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		$ 1,424,476	$ (3,735,495)	$ 203,260
(Loss) earnings per share
Basic (in dollars per share)		$ 2.01	$ (7.16)	$ 0.42
Diluted (in dollars per share)		$ 2.01	$ (7.16)	$ 0.42
Weighted average number of common shares outstanding
Basic (in shares)		708,928	521,936	479,644
Diluted (in shares)		708,928	521,936	499,743

XML

Consolidated Statements of Changes in Stockholders Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands	Total	Convertible Perpetual Preferred Stock	Common Stock	Warrants	Additional Paid-In Capital	Treasury Stock	Accumulated Deficit	Non-controlling Interest
Beginning Balance (in shares) (Predecessor) at Dec. 31, 2013		7,650
Beginning Balance (in shares) (Predecessor) at Dec. 31, 2013			490,290
Beginning Balance (Predecessor) at Dec. 31, 2013	$ 3,175,627	$ 8	$ 483		$ 5,294,551	$ (8,770)	$ (3,460,462)	$ 1,349,817
Increase (Decrease) in Stockholders' Equity
Sale of royalty trust units | Predecessor	22,119				4,091			18,028
Distributions to noncontrolling interest owners | Predecessor	(193,807)							(193,807)
Purchase of treasury stock | Predecessor	(6,373)					(6,373)
Retirement of treasury stock | Predecessor	0				(6,373)	6,373
Stock distributions, net of purchases - retirement plans (in shares) | Predecessor			206
Stock distributions, net of purchases - retirement plans | Predecessor	9				(1,781)	1,790
Stock-based compensation | Predecessor	23,665				23,665
Stock-based compensation excess tax provision | Predecessor	14				14
Payment received on shareholder receivable | Predecessor	1,250				1,250
Issuance of restricted stock awards, net of cancellations (in shares) | Predecessor			3,311
Issuance of restricted stock awards, net of cancellations | Predecessor	0		$ 3		(3)
Common stock issued for debt | Predecessor	0
Acquisition of ownership interest | Predecessor	(2,730)				(2,074)			(656)
Repurchase of common stock (in shares) | Predecessor			(27,411)
Repurchase of common stock | Predecessor	(111,827)		$ (27)		(111,800)
Conversion of preferred stock to common stock (in shares) | Predecessor		(2,000)	18,423
Conversion of preferred stock to common stock | Predecessor	0	$ (2)	$ 18		(16)
Net (loss) income | Predecessor	351,898						253,285	98,613
Convertible perpetual preferred stock dividends | Predecessor	(50,025)						(50,025)
Ending Balance (in shares) (Predecessor) at Dec. 31, 2014		5,650
Ending Balance (in shares) (Predecessor) at Dec. 31, 2014			484,819
Ending Balance (Predecessor) at Dec. 31, 2014	3,209,820	$ 6	$ 477		5,201,524	(6,980)	(3,257,202)	1,271,995
Increase (Decrease) in Stockholders' Equity
Distributions to noncontrolling interest owners | Predecessor	(138,305)							(138,305)
Purchase of treasury stock | Predecessor	(2,428)					(2,428)
Retirement of treasury stock | Predecessor	0				(2,428)	2,428
Stock distributions, net of purchases - retirement plans (in shares) | Predecessor			(1,000)
Stock distributions, net of purchases - retirement plans | Predecessor	322				(916)	1,238
Stock-based compensation | Predecessor	21,123				21,123
Payment received on shareholder receivable | Predecessor	1,250				1,250
Issuance of restricted stock awards, net of cancellations (in shares) | Predecessor			1,514
Issuance of restricted stock awards, net of cancellations | Predecessor	$ 0		$ 5		(5)
Common stock issued for debt (in shares) | Predecessor	92,800		120,881
Common stock issued for debt | Predecessor	$ 63,299		$ 121		63,178
Conversion of preferred stock to common stock (in shares) | Predecessor		(230)	2,968
Conversion of preferred stock to common stock | Predecessor	0	$ 0	$ 3		(3)
Net (loss) income | Predecessor	(4,321,051)						(3,697,545)	(623,506)
Convertible perpetual preferred stock dividends (in shares) | Predecessor			24,289
Convertible perpetual preferred stock dividends | Predecessor	$ (21,763)		$ 24		16,163		(37,950)
Ending Balance (in shares) (Predecessor) at Dec. 31, 2015		5,420
Ending Balance (in shares) (Predecessor) at Dec. 31, 2015	633,471		633,471
Ending Balance (Predecessor) at Dec. 31, 2015	$ (1,187,733)	$ 6	$ 630		5,299,886	(5,742)	(6,992,697)	510,184
Increase (Decrease) in Stockholders' Equity
Cumulative effect of adoption of ASU 2015-02 | Predecessor	(253,124)						257,081	(510,205)
Purchase of treasury stock | Predecessor	(44)					(44)
Retirement of treasury stock | Predecessor	0				(44)	44
Stock distributions, net of purchases - retirement plans (in shares) | Predecessor			603
Stock distributions, net of purchases - retirement plans | Predecessor	(336)				(860)	524
Stock-based compensation | Predecessor	11,102				11,102
Issuance of restricted stock awards, net of cancellations (in shares) | Predecessor			(2,184)
Issuance of restricted stock awards, net of cancellations | Predecessor	$ 0		$ 2		(2)
Common stock issued for debt (in shares) | Predecessor	84,400		84,390
Common stock issued for debt | Predecessor	$ 4,409		$ 84		4,325
Conversion of preferred stock to common stock (in shares) | Predecessor		(173)	2,220
Conversion of preferred stock to common stock | Predecessor	0		$ 2		(2)
Net (loss) income | Predecessor	1,440,797						1,440,797
Convertible perpetual preferred stock dividends | Predecessor	$ (16,321)						(16,321)
Ending Balance (in shares) (Predecessor) at Oct. 01, 2016		0
Ending Balance (in shares) (Predecessor) at Oct. 01, 2016			0	0
Ending Balance (in shares) (Successor) at Oct. 01, 2016	19,371		18,932	6,442
Ending Balance (in shares) at Oct. 01, 2016			18,932	6,442
Ending Balance (Predecessor) at Oct. 01, 2016	$ 0	$ 0	$ 0	$ 0	0	0	0	0
Ending Balance (Successor) at Oct. 01, 2016	827,424		19	88,382	739,023	0	0
Ending Balance at Oct. 01, 2016	827,424		$ 19	88,382	739,023	0	0
Increase (Decrease) in Stockholders' Equity
Cancellation of Predecessor equity (in shares) | Predecessor		(5,247)	(718,500)
Cancellation of Predecessor equity | Predecessor	1,250	$ (6)	$ (718)		(5,314,405)	5,218	5,311,140	$ 21
Purchase of treasury stock | Successor	(110)					(110)
Retirement of treasury stock | Successor	0				(110)	110
Stock-based compensation | Successor	6,581				6,581
Common stock issued for debt (in shares) | Successor			693
Common stock issued for debt | Successor	13,001		$ 1		13,000
Issuance of stock awards, net of cancellations (in shares) | Successor			10
Issuance of stock awards, net of cancellations | Successor	0
Conversion of preferred stock to common stock | Successor	3			$ (1)	4
Net (loss) income | Successor	$ (333,982)						(333,982)
Ending Balance (in shares) (Successor) at Dec. 31, 2016	19,635		19,635	6,442
Ending Balance (Successor) at Dec. 31, 2016	$ 512,917		$ 20	$ 88,381	$ 758,498	$ 0	$ (333,982)

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$ (333,982)
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities
Provision for doubtful accounts	(13,166)
Depreciation, depletion and amortization	37,893
Accretion of asset retirement obligations	2,090
Impairment	319,087
Gain on reorganization items, net	0
Debt issuance costs amortization	0
Amortization of discount, net of premium, on debt	(81)
Gain on extinguishment of debt	0
Write off of debt issuance costs	0
(Gain) loss on debt derivatives	0
Cash paid for early conversion of convertible notes	0
Loss (gain) on derivative contracts	25,652
Cash received on settlement of derivative contracts	7,698
Loss on settlement of contract	0
Cash paid on settlement of contract	0
Stock-based compensation	6,250
Other	717
Changes in operating assets and liabilities increasing (decreasing) cash
Deconsolidation of noncontrolling interest	0
Receivables	12,872
Prepaid expenses	(1,079)
Other current assets	(260)
Other assets and liabilities, net	1,505
Accounts payable and accrued expenses	990
Asset retirement obligations	(591)
Net cash provided by (used in) operating activities	65,595
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(51,676)
Acquisitions of assets	0
Proceeds from sale of assets	11,841
Net cash used in investing activities	(39,835)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	0
Repayments of borrowings	(414,954)
Debt issuance costs	0
Proceeds from building mortgage	0
Payment of mortgage proceeds and cash recovery to debt holders	0
Proceeds from the sale of royalty trust units	0
Noncontrolling interest distributions	0
Purchase of treasury stock	(110)
Repurchase of common stock	0
Dividends paid—preferred	0
Cash paid on settlement of financing derivative contracts	0
Other	3
Net cash (used in) provided by financing activities	(415,061)
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH	(389,301)
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	563,372
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year	174,071	$ 563,372
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income		1,440,797	$ (4,321,051)	$ 351,898
Adjustments to reconcile net (loss) income to net cash provided by (used in) operating activities
Provision for doubtful accounts		16,704	0	0
Depreciation, depletion and amortization		107,936	367,295	493,931
Accretion of asset retirement obligations		4,365	4,477	9,092
Impairment		718,194	4,534,689	192,768
Gain on reorganization items, net		(2,442,436)	0	0
Debt issuance costs amortization		4,996	11,884	9,425
Amortization of discount, net of premium, on debt		2,734	3,130	529
Gain on extinguishment of debt		(41,179)	(641,131)	0
Write off of debt issuance costs		0	7,108	0
(Gain) loss on debt derivatives		(1,324)	10,377	0
Cash paid for early conversion of convertible notes		(33,452)	(32,741)	0
Loss (gain) on derivative contracts		4,823	(73,061)	(334,011)
Cash received on settlement of derivative contracts		72,608	327,702	11,796
Loss on settlement of contract		90,184	50,976	0
Cash paid on settlement of contract		(11,000)	(24,889)	0
Stock-based compensation		9,075	18,380	19,994
Other		(3,260)	2,842	417
Changes in operating assets and liabilities increasing (decreasing) cash
Deconsolidation of noncontrolling interest		(9,654)	0	0
Receivables		36,116	201,907	(63,492)
Prepaid expenses		(5,681)	1,148	9,549
Other current assets		(181)	12,710	3,164
Other assets and liabilities, net		(7,542)	2,239	(1,132)
Accounts payable and accrued expenses		(61,305)	(86,470)	(66,492)
Asset retirement obligations		(3,595)	(3,984)	(16,322)
Net cash provided by (used in) operating activities		(112,077)	373,537	621,114
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment		(186,452)	(879,201)	(1,553,332)
Acquisitions of assets		(1,328)	(216,943)	(18,384)
Proceeds from sale of assets		20,090	56,504	714,475
Net cash used in investing activities		(167,690)	(1,039,640)	(857,241)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings		489,198	2,065,000	0
Repayments of borrowings		(74,243)	(939,466)	0
Debt issuance costs		(333)	(53,244)	(3,947)
Proceeds from building mortgage		26,847	0	0
Payment of mortgage proceeds and cash recovery to debt holders		(33,874)	0	0
Proceeds from the sale of royalty trust units		0	0	22,119
Noncontrolling interest distributions		0	(138,305)	(193,807)
Purchase of treasury stock		(44)	(3,535)	(8,702)
Repurchase of common stock		0	0	(111,827)
Dividends paid—preferred		0	(11,262)	(55,525)
Cash paid on settlement of financing derivative contracts		0	0	(44,128)
Other		0	1,250	(1,466)
Net cash (used in) provided by financing activities		407,551	920,438	(397,283)
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH		127,784	254,335	(633,410)
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	$ 563,372	435,588	181,253	814,663
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of year		$ 563,372	$ 435,588	$ 181,253

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Voluntary Reorganization under Chapter 11 Proceedings

12 Months Ended

Dec. 31, 2016

Reorganizations [Abstract]

Voluntary Reorganization under Chapter 11 Proceedings

Voluntary Reorganization under Chapter 11 Proceedings

On May 16, 2016, the Company and certain of its direct and indirect subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016 (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 “Plan”), 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 secured revolving credit facility (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 reserve-based revolving credit facility (the “New First Lien Exit Facility”). Refer to Note 11 for additional information.

• Cash Collateral Account. The Company deposited $50.0 million of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i) $12.5 million will be released to the Company upon delivery of an acceptable business plan to the administrative agent, (ii) $12.5 million will be released to the Company upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to the Company, up to $25.0 million will be released to the Company upon meeting a minimum 2.00:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017.

If no default or event of default under the New First Lien Exit Facility exists at the expiration or termination of the Protected Period, all remaining proceeds in the Cash Collateral Account will be released to the Company at that time.

• Senior Secured Notes. All outstanding obligations under the 8.75% Senior Secured Notes due 2020 issued in June 2015 and the $78.0 million principal 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC (“PGC) in October 2015, (the “PGC Senior Secured Notes”) (collectively, “Senior Secured Notes”) were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of common stock in the Successor Company (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal amount of newly issued, non-interest bearing 0.00% convertible senior subordinated notes due 2020, (the “New Convertible Notes”), which are mandatorily convertible into approximately 15.0 million shares of New Common Stock upon the first to occur of several triggering events, one of which is refinancing of the New First Lien Exit Facility. Refer to Note 11 and Note 15 for additional information.

• General Unsecured Claims.The Company’s general unsecured claims, including 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 (collectively, the “Senior Unsecured Notes”) and the 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, 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 New 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, with initial exercise prices of $41.34 and $42.03 per share, respectively, which expire on October 4, 2022, (the “Warrants”). Refer to Note 11 and Note 15 for additional information.

• New Building Note. A note with a principal amount of $35.0 million, which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) 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 Unsecured Senior Notes. Refer to Note 11 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. Refer to Note 15 for additional information.

Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company’s post-emergence board of directors is comprised of five directors, including the Company’s Chief Executive Officer, James Bennett, and four non-employee directors, Michael L. Bennett, John V. Genova, William “Bill” M. Griffin, Jr. and David J. Kornder.

Fresh Start Accounting

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.

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, fresh start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2016 and related fresh start adjustments are included in the accompanying statement of operations for the period from January 1, 2016 through October 1, 2016 (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 period after October 1, 2016 (the “Successor 2016 Period”) will not be 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.

Reorganization Value. Reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate 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 is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s 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 $1.04 billion to $1.32 billion, which was subsequently approved by the Bankruptcy Court. 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. Based on the estimates and assumptions used in determining the enterprise value, the Company estimated the enterprise value to be approximately $1.09 billion.

Valuation of Oil and Gas Properties. The Company’s principal assets are its oil and gas properties, which are accounted for under the Full Cost Accounting method as described in Note 3. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.

The fair value analysis performed by valuation experts was based on the Company’s estimates of proved reserves as developed internally by the Company’s reserves engineers. Discounted cash flow models were prepared using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising the proved reserves. Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company. Development and operating costs from proved reserves estimates were adjusted for inflation. A risk adjustment factor was applied to the proved undeveloped reserve category. The discounted cash flow models also included estimates not typically included in proved reserves such as depreciation and income tax expenses.

The risk adjusted after tax cash flows were discounted at 10%. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants.

From this analysis the Company concluded the fair value of its proved reserves was $632.8 million as of the Emergence Date. The Company also reviewed its undeveloped leasehold acreage and concluded that the fair value of undeveloped leasehold acreage was $113.9 million based on analysis of comparable market transactions. These amounts are reflected in the Fresh Start Adjustments item number 14 below.

The following table reconciles the enterprise value to the estimated fair value of the Successor Company's common stock as of the Emergence Date (in thousands, except per share amounts):

Enterprise value	$	1,089,808
Plus: Cash and cash equivalents	563,372
Less: Fair value of New Building Note	(36,610		)
Less: Asset retirement obligation	(92,412		)
Less: Fair value of New First Lien Exit Facility	(414,954		)
Less: Fair value of New Convertible Notes	(445,660		)
Less: Fair value of warrants, including warrants held in reserve for settlement of general unsecured claims	(95,794		)
Fair value of Successor common stock issued upon emergence	$	567,750
Shares issued upon emergence on October 4, 2016, including shares held in reserve for settlement of general unsecured claims	19,371
Per share value	$	29.31

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 equivalents	563,372
Plus: other working capital liabilities	131,766
Plus: other long-term liabilities	8,549
Reorganization value of Successor assets	$	1,793,495

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.

Consolidated Balance Sheet. The adjustments included in the following consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company on the Emergence Date (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.

The following table reflects the reorganization and application of Accounting Standards Codification (“ASC”) 852 “Reorganizations” on the consolidated balance sheet as of October 1, 2016 (in thousands):

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
ASSETS
Current assets
Cash and cash equivalents	$	652,680		$	(142,148	)	(1)	$	—			$	510,532
Restricted cash - collateral	—			50,000			(2)	—				50,000
Restricted cash - other	—			2,840			(2)	—				2,840
Accounts receivable, net	61,446			12,356			(3)	—				73,802
Derivative contracts	10,192			—				(669		)	(12)	9,523
Prepaid expenses	12,514			(8,218		)	(4)	—				4,296
Other current assets	1,003			—				3,217			(13)	4,220
Total current assets	737,835			(85,170		)		2,548				655,213
Oil and natural gas properties, using full cost method of accounting
Proved	12,093,492			—				(11,344,684		)	(14)	748,808
Unproved	322,580			—				(205,578		)	(14)	117,002
Less: accumulated depreciation, depletion and impairment	(11,637,538		)	—				11,637,538			(14)	—
	778,534			—				87,276				865,810
Other property, plant and equipment, net	357,528			(41		)		(93,782		)	(15)	263,705
Derivative contracts	70			—				(70		)	(12)	—
Other assets	12,537			(3,770		)	(5)	—				8,767
Total assets	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	140,448		$	(14,820	)	(6)	$	—			$	125,628
Derivative contracts	2,982			—				1,666			(12)	4,648
Asset retirement obligations	8,573			—				57,105			(16)	65,678
Total current liabilities	152,003			(14,820		)		58,771				195,954
Long-term debt	—			731,735			(7)	1,610			(17)	733,345
Derivative contracts	935			—				304			(12)	1,239
Asset retirement obligations	62,896			—				(36,161		)	(16)	26,735
Other long-term obligations	3			8,798			(8)	(3		)		8,798
Liabilities subject to compromise	4,346,188			(4,346,188		)	(9)	—				—
Total liabilities	4,562,025			(3,620,475		)		24,521				966,071
Equity
SandRidge Energy, Inc. stockholders’ equity (deficit)
Predecessor preferred stock	6			—				(6		)	(18)	—
Predecessor common stock	718			—				(718		)	(18)	—
Predecessor additional paid-in capital	5,315,655			—				(5,315,655		)	(18)	—
Predecessor additional paid-in capital—stockholder receivable	(1,250		)	1,250			(10)	—				—
Predecessor treasury stock, at cost	(5,218		)	—				5,218			(18)	—
Successor common stock	—			19			(11)	—				19
Successor warrants	—			88,382			(11)	—				88,382
Successor additional paid-in capital	—			739,023			(11)	—				739,023
Accumulated deficit	(7,985,411		)	2,702,820			(9)	5,282,591			(19)	—
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	(2,675,500		)	3,531,494				(28,570		)		827,424
Noncontrolling interest	(21		)	—				21			(20)	—
Total stockholders’ (deficit) equity	(2,675,521		)	3,531,494				(28,549		)		827,424
Total liabilities and stockholders’ equity (deficit)	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

Reorganization Adjustments

1. Reflects the net cash payments made upon emergence (in thousands):

Sources:
Proceeds from New Building Note	$	26,847
Total sources	$	26,847
Uses and transfers:
Cash transferred to restricted accounts (collateral and general unsecured claims)	$	52,840
Payments and funding of escrow account related to professional fees	43,770
Payment on Senior Credit facility (principal and interest)	35,238
Repayment of Senior Secured Notes and Unsecured Notes	33,874
Payment of certain contract cures and other	3,273
Total uses and transfers	168,995
Net uses and transfers	$	(142,148	)

2. Funding of $50.0 million Cash Collateral account and the funding of $2.8 million to be held in reserve by the Company for distribution to satisfy allowed general unsecured claims as specified under the Plan.

3. Accrual for future reimbursement of the unused portion of the professional fees escrow account and other receivables.

4. Write-off of prepaid expenses primarily related to $7.5 million of prepaid premium for the Predecessor Company’s directors and officers insurance policy.

5. Application of a $3.8 million deposit held by a utility service toward the settlement of the utility service’s claims under the Plan.

6. Includes a $43.8 million decrease in accrued liabilities as a result of funding an escrow account established for the payment of professional fees, partially offset by the reinstatement of certain liabilities subject to compromise as accounts payable and accrued expenses.

7. Principal balances of $35.0 million of the New Building Note, $281.8 million of the New Convertible Notes, and the $415.0 million drawn on the New First Lien Exit Facility.

8. Reclassification of non-qualified deferred compensation plan and gas balancing liabilities from liabilities subject to compromise to other long term obligations, as these liabilities became obligations of the Successor.

9. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):

Current maturities of long-term debt and accrued interest	$	4,179,483
Accounts payable and accrued expenses	157,422
Other long-term liabilities	9,283
Liabilities subject to compromise of the Predecessor	4,346,188
Cash payments at emergence	(72,385		)
Cash proceeds from building mortgage	26,847
Write-off of prepaid accounts upon emergence	(8,218		)
Accrual for future reimbursement from professional fees escrow account and other receivables	12,356
Total consideration given pursuant to the Plan:
Fair value of equity issued	(827,424		)
Principal value of long-term debt issued and reinstated at emergence	(731,735		)
Reinstatement of liabilities subject to compromise as accounts payable and accrued expenses	(37,789		)
Release of stockholder receivable	(1,250		)
Application of deposit held by utility services	(3,770		)
Gain on settlement of liabilities subject to compromise	$	2,702,820

10. Release of a receivable from the Predecessor’s former director and officer as outlined in the Plan.

11. The following table reconciles reorganization adjustments made to Successor common stock, warrants and additional paid in capital (in thousands):

Par value of 18.9 million shares of New Common Stock issued to former holders of the Senior Secured Notes and Unsecured Notes (valued at $29.31 per share)	$	19
Fair value of warrants issued to holders of the Unsecured Notes(1)	88,382
Additional paid in capital - New Common Stock	575,144
Additional paid in capital - premium on New Convertible Notes(2)	163,879
Total Successor Company equity issued on Emergence Date	$	827,424

____________________

(1) The fair value of the warrants was estimated using a Black-Scholes-Merton model with the following assumptions: implied stock price of the Successor Company; exercise price per share of $41.34 and $42.03 for Warrant classes A and B, respectively; expected volatility of 59.26%; risk free interest rate, continuously compounded, of 1.36%; and holding period of six years.

(2) The fair value of the New Convertible Notes was estimated using a Monte Carlo simulation with the following assumptions; the implied Successor Company stock price; expected volatility of 56.06%; risk free interest rate, continuously compounded, of 1.08%; recovery rate of 15.00%; hazard rate of 12.41%; drop on default of 100.00%; and termination period after four years. The premium is the difference between the fair value of the New Convertible Notes of $445.7 million and the principal value of the New Convertible Notes of $281.8 million.

Fresh Start Adjustments

12. Adjustments and reclassifications of derivative contracts based on their Emergence Date fair values, which were determined using the fair value methodology for commodity derivative contracts discussed in Note 6.

13. Fair value adjustment to other current assets to record assets held for sale at their anticipated sales prices.

14. Fair value adjustments to oil and natural gas properties, including asset retirement obligation, associated inventory, unproved acreage and seismic. See above for detailed discussion of fair value methodology.

15. Adjustments to other property, plant and equipment to record the assets at their respective fair values on the Emergence Date. A combination of the cost approach and income approach were utilized to determine the fair values of the Company’s headquarters and other properties located in downtown Oklahoma City, Oklahoma, and the cost approach was utilized to determine the fair value of all other property, plant and equipment.

16. Fair value adjustments to the Company’s asset retirement obligations as a result of applying fresh start accounting. Upon implementation of fresh start accounting, the Company revalued these obligations based upon updates to wells’ productive lives and application of the Successor Company’s credit adjusted risk fee rate.

17. Fair value adjustment to record premium on the New Building Note.

18. Cancellation of Predecessor Company’s common stock, preferred stock, treasury stock and paid-in capital.

19. Adjustment to reset retained deficit to zero.

20. Elimination of the Predecessor non-controlling interest.

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 settlements	84,228
Loss on mortgage	(8,153		)
Gain on preferred stock dividends	37,893
Fresh start valuation adjustments	(28,549		)
Fair value of equity issued	(827,424		)
Principal value of New Convertible Notes issued	(281,780		)
Gain on reorganization items, net	$	2,430,599

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Fresh Start Accounting

12 Months Ended

Dec. 31, 2016

Fresh-Start Adjustment [Line Items]

Fresh Start Accounting

Voluntary Reorganization under Chapter 11 Proceedings

On May 16, 2016, the Company and certain of its direct and indirect subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016 (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 “Plan”), 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 secured revolving credit facility (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 reserve-based revolving credit facility (the “New First Lien Exit Facility”). Refer to Note 11 for additional information.

• Cash Collateral Account. The Company deposited $50.0 million of cash in an account controlled by the administrative agent to the New First Lien Exit Facility (the “Cash Collateral Account”) from the Emergence Date until the first borrowing base redetermination in October 2018 (the “Protected Period”); provided that (a) (i) $12.5 million will be released to the Company upon delivery of an acceptable business plan to the administrative agent, (ii) $12.5 million will be released to the Company upon achievement for two consecutive quarters of certain milestones set forth in the business plan and (b) to the extent the foregoing amounts are not released to the Company, up to $25.0 million will be released to the Company upon meeting a minimum 2.00:1.00 ratio of proved developed producing reserves to aggregate principal loan commitments under the New First Lien Exit Facility at any time after July 4, 2017.

If no default or event of default under the New First Lien Exit Facility exists at the expiration or termination of the Protected Period, all remaining proceeds in the Cash Collateral Account will be released to the Company at that time.

• Senior Secured Notes. All outstanding obligations under the 8.75% Senior Secured Notes due 2020 issued in June 2015 and the $78.0 million principal 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC (“PGC) in October 2015, (the “PGC Senior Secured Notes”) (collectively, “Senior Secured Notes”) were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of common stock in the Successor Company (the “New Common Stock”) issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal amount of newly issued, non-interest bearing 0.00% convertible senior subordinated notes due 2020, (the “New Convertible Notes”), which are mandatorily convertible into approximately 15.0 million shares of New Common Stock upon the first to occur of several triggering events, one of which is refinancing of the New First Lien Exit Facility. Refer to Note 11 and Note 15 for additional information.

• General Unsecured Claims.The Company’s general unsecured claims, including 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 (collectively, the “Senior Unsecured Notes”) and the 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes” and together with the Senior Unsecured Notes, 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 New 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, with initial exercise prices of $41.34 and $42.03 per share, respectively, which expire on October 4, 2022, (the “Warrants”). Refer to Note 11 and Note 15 for additional information.

• New Building Note. A note with a principal amount of $35.0 million, which is secured by first priority mortgages on the Company’s headquarters facility and certain other non-oil and gas real property located in downtown Oklahoma City, Oklahoma (the “New Building Note”) 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 Unsecured Senior Notes. Refer to Note 11 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. Refer to Note 15 for additional information.

Additionally, pursuant to the Plan confirmed by the Bankruptcy Court, the Company’s post-emergence board of directors is comprised of five directors, including the Company’s Chief Executive Officer, James Bennett, and four non-employee directors, Michael L. Bennett, John V. Genova, William “Bill” M. Griffin, Jr. and David J. Kornder.

Fresh Start Accounting

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.

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, fresh start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2016 and related fresh start adjustments are included in the accompanying statement of operations for the period from January 1, 2016 through October 1, 2016 (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 period after October 1, 2016 (the “Successor 2016 Period”) will not be 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.

Reorganization Value. Reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate 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 is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s 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 $1.04 billion to $1.32 billion, which was subsequently approved by the Bankruptcy Court. 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. Based on the estimates and assumptions used in determining the enterprise value, the Company estimated the enterprise value to be approximately $1.09 billion.

Valuation of Oil and Gas Properties. The Company’s principal assets are its oil and gas properties, which are accounted for under the Full Cost Accounting method as described in Note 3. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.

The fair value analysis performed by valuation experts was based on the Company’s estimates of proved reserves as developed internally by the Company’s reserves engineers. Discounted cash flow models were prepared using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising the proved reserves. Future revenues were based upon forward strip oil and natural gas prices as of the emergence date, adjusted for differentials realized by the Company. Development and operating costs from proved reserves estimates were adjusted for inflation. A risk adjustment factor was applied to the proved undeveloped reserve category. The discounted cash flow models also included estimates not typically included in proved reserves such as depreciation and income tax expenses.

The risk adjusted after tax cash flows were discounted at 10%. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants.

From this analysis the Company concluded the fair value of its proved reserves was $632.8 million as of the Emergence Date. The Company also reviewed its undeveloped leasehold acreage and concluded that the fair value of undeveloped leasehold acreage was $113.9 million based on analysis of comparable market transactions. These amounts are reflected in the Fresh Start Adjustments item number 14 below.

The following table reconciles the enterprise value to the estimated fair value of the Successor Company's common stock as of the Emergence Date (in thousands, except per share amounts):

Enterprise value	$	1,089,808
Plus: Cash and cash equivalents	563,372
Less: Fair value of New Building Note	(36,610		)
Less: Asset retirement obligation	(92,412		)
Less: Fair value of New First Lien Exit Facility	(414,954		)
Less: Fair value of New Convertible Notes	(445,660		)
Less: Fair value of warrants, including warrants held in reserve for settlement of general unsecured claims	(95,794		)
Fair value of Successor common stock issued upon emergence	$	567,750
Shares issued upon emergence on October 4, 2016, including shares held in reserve for settlement of general unsecured claims	19,371
Per share value	$	29.31

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 equivalents	563,372
Plus: other working capital liabilities	131,766
Plus: other long-term liabilities	8,549
Reorganization value of Successor assets	$	1,793,495

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.

Consolidated Balance Sheet. The adjustments included in the following consolidated balance sheet reflect the effects of the transactions contemplated by the Plan and carried out by the Company on the Emergence Date (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.

The following table reflects the reorganization and application of Accounting Standards Codification (“ASC”) 852 “Reorganizations” on the consolidated balance sheet as of October 1, 2016 (in thousands):

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
ASSETS
Current assets
Cash and cash equivalents	$	652,680		$	(142,148	)	(1)	$	—			$	510,532
Restricted cash - collateral	—			50,000			(2)	—				50,000
Restricted cash - other	—			2,840			(2)	—				2,840
Accounts receivable, net	61,446			12,356			(3)	—				73,802
Derivative contracts	10,192			—				(669		)	(12)	9,523
Prepaid expenses	12,514			(8,218		)	(4)	—				4,296
Other current assets	1,003			—				3,217			(13)	4,220
Total current assets	737,835			(85,170		)		2,548				655,213
Oil and natural gas properties, using full cost method of accounting
Proved	12,093,492			—				(11,344,684		)	(14)	748,808
Unproved	322,580			—				(205,578		)	(14)	117,002
Less: accumulated depreciation, depletion and impairment	(11,637,538		)	—				11,637,538			(14)	—
	778,534			—				87,276				865,810
Other property, plant and equipment, net	357,528			(41		)		(93,782		)	(15)	263,705
Derivative contracts	70			—				(70		)	(12)	—
Other assets	12,537			(3,770		)	(5)	—				8,767
Total assets	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	140,448		$	(14,820	)	(6)	$	—			$	125,628
Derivative contracts	2,982			—				1,666			(12)	4,648
Asset retirement obligations	8,573			—				57,105			(16)	65,678
Total current liabilities	152,003			(14,820		)		58,771				195,954
Long-term debt	—			731,735			(7)	1,610			(17)	733,345
Derivative contracts	935			—				304			(12)	1,239
Asset retirement obligations	62,896			—				(36,161		)	(16)	26,735
Other long-term obligations	3			8,798			(8)	(3		)		8,798
Liabilities subject to compromise	4,346,188			(4,346,188		)	(9)	—				—
Total liabilities	4,562,025			(3,620,475		)		24,521				966,071
Equity
SandRidge Energy, Inc. stockholders’ equity (deficit)
Predecessor preferred stock	6			—				(6		)	(18)	—
Predecessor common stock	718			—				(718		)	(18)	—
Predecessor additional paid-in capital	5,315,655			—				(5,315,655		)	(18)	—
Predecessor additional paid-in capital—stockholder receivable	(1,250		)	1,250			(10)	—				—
Predecessor treasury stock, at cost	(5,218		)	—				5,218			(18)	—
Successor common stock	—			19			(11)	—				19
Successor warrants	—			88,382			(11)	—				88,382
Successor additional paid-in capital	—			739,023			(11)	—				739,023
Accumulated deficit	(7,985,411		)	2,702,820			(9)	5,282,591			(19)	—
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	(2,675,500		)	3,531,494				(28,570		)		827,424
Noncontrolling interest	(21		)	—				21			(20)	—
Total stockholders’ (deficit) equity	(2,675,521		)	3,531,494				(28,549		)		827,424
Total liabilities and stockholders’ equity (deficit)	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

Reorganization Adjustments

1. Reflects the net cash payments made upon emergence (in thousands):

Sources:
Proceeds from New Building Note	$	26,847
Total sources	$	26,847
Uses and transfers:
Cash transferred to restricted accounts (collateral and general unsecured claims)	$	52,840
Payments and funding of escrow account related to professional fees	43,770
Payment on Senior Credit facility (principal and interest)	35,238
Repayment of Senior Secured Notes and Unsecured Notes	33,874
Payment of certain contract cures and other	3,273
Total uses and transfers	168,995
Net uses and transfers	$	(142,148	)

2. Funding of $50.0 million Cash Collateral account and the funding of $2.8 million to be held in reserve by the Company for distribution to satisfy allowed general unsecured claims as specified under the Plan.

3. Accrual for future reimbursement of the unused portion of the professional fees escrow account and other receivables.

4. Write-off of prepaid expenses primarily related to $7.5 million of prepaid premium for the Predecessor Company’s directors and officers insurance policy.

5. Application of a $3.8 million deposit held by a utility service toward the settlement of the utility service’s claims under the Plan.

6. Includes a $43.8 million decrease in accrued liabilities as a result of funding an escrow account established for the payment of professional fees, partially offset by the reinstatement of certain liabilities subject to compromise as accounts payable and accrued expenses.

7. Principal balances of $35.0 million of the New Building Note, $281.8 million of the New Convertible Notes, and the $415.0 million drawn on the New First Lien Exit Facility.

8. Reclassification of non-qualified deferred compensation plan and gas balancing liabilities from liabilities subject to compromise to other long term obligations, as these liabilities became obligations of the Successor.

9. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):

Current maturities of long-term debt and accrued interest	$	4,179,483
Accounts payable and accrued expenses	157,422
Other long-term liabilities	9,283
Liabilities subject to compromise of the Predecessor	4,346,188
Cash payments at emergence	(72,385		)
Cash proceeds from building mortgage	26,847
Write-off of prepaid accounts upon emergence	(8,218		)
Accrual for future reimbursement from professional fees escrow account and other receivables	12,356
Total consideration given pursuant to the Plan:
Fair value of equity issued	(827,424		)
Principal value of long-term debt issued and reinstated at emergence	(731,735		)
Reinstatement of liabilities subject to compromise as accounts payable and accrued expenses	(37,789		)
Release of stockholder receivable	(1,250		)
Application of deposit held by utility services	(3,770		)
Gain on settlement of liabilities subject to compromise	$	2,702,820

10. Release of a receivable from the Predecessor’s former director and officer as outlined in the Plan.

11. The following table reconciles reorganization adjustments made to Successor common stock, warrants and additional paid in capital (in thousands):

Par value of 18.9 million shares of New Common Stock issued to former holders of the Senior Secured Notes and Unsecured Notes (valued at $29.31 per share)	$	19
Fair value of warrants issued to holders of the Unsecured Notes(1)	88,382
Additional paid in capital - New Common Stock	575,144
Additional paid in capital - premium on New Convertible Notes(2)	163,879
Total Successor Company equity issued on Emergence Date	$	827,424

____________________

(1) The fair value of the warrants was estimated using a Black-Scholes-Merton model with the following assumptions: implied stock price of the Successor Company; exercise price per share of $41.34 and $42.03 for Warrant classes A and B, respectively; expected volatility of 59.26%; risk free interest rate, continuously compounded, of 1.36%; and holding period of six years.

(2) The fair value of the New Convertible Notes was estimated using a Monte Carlo simulation with the following assumptions; the implied Successor Company stock price; expected volatility of 56.06%; risk free interest rate, continuously compounded, of 1.08%; recovery rate of 15.00%; hazard rate of 12.41%; drop on default of 100.00%; and termination period after four years. The premium is the difference between the fair value of the New Convertible Notes of $445.7 million and the principal value of the New Convertible Notes of $281.8 million.

Fresh Start Adjustments

12. Adjustments and reclassifications of derivative contracts based on their Emergence Date fair values, which were determined using the fair value methodology for commodity derivative contracts discussed in Note 6.

13. Fair value adjustment to other current assets to record assets held for sale at their anticipated sales prices.

14. Fair value adjustments to oil and natural gas properties, including asset retirement obligation, associated inventory, unproved acreage and seismic. See above for detailed discussion of fair value methodology.

15. Adjustments to other property, plant and equipment to record the assets at their respective fair values on the Emergence Date. A combination of the cost approach and income approach were utilized to determine the fair values of the Company’s headquarters and other properties located in downtown Oklahoma City, Oklahoma, and the cost approach was utilized to determine the fair value of all other property, plant and equipment.

16. Fair value adjustments to the Company’s asset retirement obligations as a result of applying fresh start accounting. Upon implementation of fresh start accounting, the Company revalued these obligations based upon updates to wells’ productive lives and application of the Successor Company’s credit adjusted risk fee rate.

17. Fair value adjustment to record premium on the New Building Note.

18. Cancellation of Predecessor Company’s common stock, preferred stock, treasury stock and paid-in capital.

19. Adjustment to reset retained deficit to zero.

20. Elimination of the Predecessor non-controlling interest.

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 settlements	84,228
Loss on mortgage	(8,153		)
Gain on preferred stock dividends	37,893
Fresh start valuation adjustments	(28,549		)
Fair value of equity issued	(827,424		)
Principal value of New Convertible Notes issued	(281,780		)
Gain on reorganization items, net	$	2,430,599

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Fresh Start Accounting. Upon emergence from bankruptcy the Company adopted fresh start accounting. See Note 2 for further details.

Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent and Rockies regions of the United States. The Company’s Rockies properties were acquired during the fourth quarter of 2015. Additionally, the Company owned interests in the Gulf of Mexico and Gulf Coast until February 2014, as discussed in Note 5.

Principles of Consolidation. The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and satisfaction of liabilities in the normal course of business. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. During the years ended December 31, 2015, and 2014, the Company fully consolidated the activities of each the SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Mississippian Trust II (the “Mississippian Trust II”) and SandRidge Permian Trust (the “Permian Trust”) (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) as variable interest entities (“VIEs”) for which the Company was the primary beneficiary. Activities of the Royalty Trusts attributable to third party ownership were presented as noncontrolling interest and included as a component of equity in the condensed consolidated balance sheet as of December 31, 2015. As discussed further below, during the year ended December 31, 2016, the Company proportionately consolidated the activities of the Royalty Trusts. All significant intercompany accounts and transactions have been eliminated in consolidation.

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 natural gas liquids (“NGL”) reserves; impairment tests of long-lived assets; 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 Companymaintains 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 exploration, production and treating services for 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 collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. As part of fresh start accounting, the allowance for doubtful accounts was reset to zero on the Emergence Date. Refer to Note 7 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, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 6 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 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. Fair value measurements for the electrical asset were based on replacement cost. Inputs used in the cost approach are based on the cost to a market participant buyer to acquire or construct a substitute asset of comparable utility, adjusted for inutility. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 6.

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.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. 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 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 12 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 Company capitalized internal costs during the Successor 2016 Period of $4.0 million and the Predecessor Company capitalized internal costs of $22.7 million, $45.1 million and $55.4 million to the full cost pool during the Predecessor 2016 Period and the years ended December 31, 2015 and 2014, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. 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.

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 an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. 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 drilling equipment, natural gas gathering and treating equipment, electrical infrastructure, transportation equipment and other property and equipment are carried at cost. 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 10 to 39 years for buildings and 2 to 30 years for equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. As part of fresh start accounting, property, plant and equipment were adjusted to their estimated fair value and depreciable lives were revised as of October 1, 2016, as described in Note 2.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 9 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 Predecessor 2016 Period and years ended December 31, 2015 and 2014, the Predecessor Company capitalized interest of approximately, $2.2 million, $10.8 million and $14.7 million, respectively, on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally, the Predecessor Company capitalized interest of $3.3 million and $5.0 million in 2015 and 2014, respectively, on midstream and corporate assets which were under construction.

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 scheduled maturity period of the related debt. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.

Investments. Investments in marketable equity securities relate primarily to the Company’s non-qualified deferred compensation plan, and have been designated as available for sale and measured at fair value using quoted prices readily available in the market pursuant to the 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 sheets.

Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, 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 well is sold, at which time 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 rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 13 for further discussion of the Company’s asset retirement obligations. As part of fresh start accounting, the ARO liabilities were adjusted to their estimated fair value as described in Note 2.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company has made an accounting policy election to deduct transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $7.4 million of transportation costs as a reduction from revenues in the Successor 2016 Period versus the presentation of $26.2 million, $45.3 million and $35.6 million of these costs as production expenses in the Predecessor 2016 Period, and the years ended December 31, 2015 and 2014, respectively. and Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $1.7 million and $1.5 million at December 31, 2016 and 2015, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

For the years ended December 31, 2015 and 2014, the Company recognized revenues and expenses generated from daywork and footage drilling contracts as the services were performed since the Company did not bear the risk of completion of the well. The Company received lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another were recognized at the time mobilization services were performed. Revenues and expenses related to drilling and services are included in other revenue and expense in the accompanying consolidated statements of operations for the years ended December 31, 2015 and 2014.

In general, natural gas purchased and sold by the midstream business was priced at a published daily or monthly index price. Sales to wholesale customers typically incorporated a premium for managing their transmission and balancing requirements. Midstream services revenues were recognized upon delivery of natural gas to customers and/or when services were rendered, pricing was determined and collectability was reasonably assured. Revenues from third-party midstream services were presented on a gross basis, since the Company acted as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold. Revenues and expenses related to midstream and marketing are included in other revenue and expense in the accompanying consolidated statements of operations for the years ended December 31, 2015 and 2014.

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 are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.

Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the Successor Company consist of unvested restricted stock awards 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.

Under the if-converted method, the Successor Company assumes the conversion of the New Convertible Notes to common stock and determines if it is more dilutive than including the expense associated with the New Convertible Notes in the computation of income available to common stockholders. Under the if-converted method, the Predecessor Company assumed the conversion of the preferred stock or Convertible Senior Unsecured Notes to common stock 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 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 19 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. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 14 for discussion of the Company’s commitments and contingencies.

Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its commodity derivative counterparties and considers its counterparties’ 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 its exposure to any individual counterparty.

A default by the Company under its New First Lien Exit Facility constitutes a default under its commodity derivative contracts with counterparties that are lenders under the New First Lien Exit 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 First Lien Exit Facility can be offset against amounts owed, if any, to such counterparty under the Company’s First Lien Exit 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 consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major 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 the Company’s ability to sell the oil, natural gas and NGLs it produces.

The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):

	Sales		% of Revenue
Period from October 2, 2016 through December 31, 2016 - Successor
Targa Pipeline Mid-Continent West OK LLC	$	35,845	36.4	%
Plains Marketing, L.P.	$	32,022	32.5	%
Period from January 1, 2016 through October 1, 2016 - Predecessor
Plains Marketing, L.P.	$	110,370	37.6	%
Targa Pipeline Mid-Continent West OK LLC	$	108,238	36.8	%
December 31, 2015 - Predecessor
Plains Marketing, L.P.	$	318,018	41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649	30.1	%
December 31, 2014 - Predecessor
Plains Marketing, L.P.	$	597,117	38.3	%
Targa Pipeline Mid-Continent West OK LLC	$	333,027	21.4	%

Recent Accounting Pronouncements. The Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2015-02, “Amendments to the Consolidation Analysis,” which simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a VIE. The requirements of the guidance were effective for annual reporting periods beginning January 1, 2016 for the Company, including interim periods within that reporting period, with early adoption permitted. The Company adopted this guidance on January 1, 2016, which resulted in the determination that the Royalty Trusts no longer qualify as VIEs. As a result, the Successor and Predecessor Companies proportionately consolidated the activities of the Royalty Trusts in 2016. Under the proportionate consolidation method, the Company accounts for only its share of each Royalty Trust’s asset, liabilities, revenues and expenses within the appropriate classifications in the accompanying consolidated financial statements. The Company adopted the provisions of ASU 2015-02 on a modified retrospective approach by recording a cumulative-effect adjustment as of January 1, 2016 that resulted in decreases of approximately $243.4 million to total assets and approximately $510.2 million to noncontrolling interest and increases of approximately $9.7 million to accounts payable and approximately $257.1 million to retained earnings. These adjustments had no impact on prior period balances.

The FASB issued ASU 2015-03, "Interest-Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs," which requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. The guidance was adopted on January 1, 2016, and resulted in a decrease of approximately $69.1 million to other assets and current maturities of long-term debt in the accompanying consolidated balance sheet for the year ended December 31, 2015, with no impact to the accompanying consolidated statements of operations. See Note 11 for treatment and classification of unamortized debt issuance costs subsequent to filing the Chapter 11 petitions. In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements,” which excludes line-of-credit debt issuance costs from the scope of ASU 2015-03. The guidance was adopted on January 1, 2016 in conjunction with the adoption of ASU 2015-03. The Company made an accounting policy election to present line-of-credit arrangement debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement. The adoption of this ASU resulted in no impact to the consolidated financial statements.

The FASB issued ASU 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The Company adopted the provisions of this ASU for the year ended December 31, 2016 on a prospective basis. The adoption of this ASU had no impact to the Company’s disclosures included in this report.

The FASB issued ASU 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments” which eliminates diversity in practice in assessing embedded contingent call (put) options in debt instruments. The ASU requires adoption by application of a modified retrospective approach to existing and future debt instruments. The ASU is effective for the Company beginning January 1, 2017, with early adoption permitted. The Company early adopted the provisions of this ASU on the Emergence Date. The adoption of this ASU resulted in no impact to the consolidated financial statements and related disclosures.

The FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Share-Based Payment Accounting” which was part of the FASB simplification initiative and involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance requires adoption by various application methods, effective for the Company beginning January 1, 2017. The Company early adopted all provisions of this ASU on the Emergence Date. Upon adoption, the Company made an accounting policy election to account for forfeitures as they occur. The adoption of this ASU resulted in no impact to the consolidated financial statements and related disclosures.

The FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” to require inclusion of amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. This ASU is effective for the Company beginning January 1, 2018. The Company early adopted the provisions of this ASU on December 31, 2016, using a retrospective transition method for each period presented. As a result of the adoption, the Company included $52.8 million of restricted cash in the beginning of period and end of period total amounts shown on the Successor statement of cash flows for October 2, 2016 and December 31, 2016, respectively. There was no impact to the Predecessor statement of cash flows.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which provides guidance concerning the recognition and measurement of revenue 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 defers the effective date of ASU 2014-09 to January 1, 2018 for the Company, with early adoption permitted in 2017. The ASU must be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes 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 does not plan to early adopt and is currently evaluating the effect that the updated standard will have on its consolidated financial statements and related disclosures.

The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for the Company on January 1, 2019. Early adoption is permitted. The Company does not plan to early adopt and is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

The FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” with the objective of reducing the existing diversity in practice of classification on certain cash receipts and payments in the statement of cash flows. The guidance requires adoption by application of a retrospective method to each period presented. The amendments are effective for the Company on January 1, 2018, with early adoption permitted. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements.

The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory” which removes 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 are effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU should be applied 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 does not plan to early adopt and is currently evaluating the effect that the guidance will have on its consolidated financial statements.

The FASB Issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides more consistency in applying the guidance, reduces the costs of application, and makes the definition of a business more operable. The ASU is effective for the Company on January 1, 2018 and amendments should be applied prospectively on and after January 1, 2018. Due to the prospective nature of the ASU, the Company cannot evaluate the impact to its consolidated financial statements until after adoption, and no disclosures are required upon transition.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items	$	—		$	(55,606	)	$	—		$	—
Cash paid for interest, net of amounts capitalized	$	(1,183	)	$	(104,609	)	$	(296,386	)	$	(235,793	)
Cash (paid) received for income taxes	$	—		$	(28	)	$	(88	)	$	1,928
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	$	10,630		$	25,045		$	177,586		$	(55,557	)
Equity issued for debt	$	(13,001	)	$	(4,409	)	$	(63,299	)	$	—
Preferred stock dividends paid in common stock	$	—		$	—		$	(16,188	)	$	—
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$	—		$	—		$	(50,310	)	$	—

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2016

Acquisitions And Dispositions [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

Predecessor Acquisitions and Divestitures

2016 Divestiture

Divestiture of West Texas Overthrust Properties and Release from Treating Agreement. On January 21, 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 West Texas Overthrust (“WTO”) to Occidental Petroleum Corporation (“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.

2015 Acquisitions

Acquisition of Piñon Gathering Company, LLC. In October 2015, the Company acquired all of the assets of and terminated a gathering agreement with PGC for $48.0 million in cash and $78.0 million principal amount of newly issued PGC Senior Secured Notes. PGC owned approximately 370 miles of gathering lines supporting the natural gas production from the Company's Piñon field in the WTO. The transaction resulted in the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. The fair value of the consideration paid by the Company, including discount attributable to the PGC Senior Secured Notes, was approximately $98.3 million and was allocated on a fair value basis between the assets acquired (approximately $47.3 million) and a loss on the termination of the gathering contract (approximately $51.0 million).

Acquisition of Rockies Properties. In December 2015, the Company acquired approximately 135,000 net acres in the North Park Basin in the Rockies, in Jackson County, Colorado. The Company paid approximately $191.1 million in cash, including post-closing adjustments, and received $3.1 million from the seller for overriding royalty interests. Also included in the acquisition were working interests in 16 wells previously drilled on the acreage.

2014 Divestiture

Sale of Gulf of Mexico and Gulf Coast Properties. On February 25, 2014, the Company sold subsidiaries that owned the Company’s Gulf of Mexico and Gulf Coast oil and natural gas properties (collectively, the “Gulf Properties”) for approximately $702.6 million, net of working capital adjustments and post-closing adjustments, and the buyer’s assumption of approximately $366.0 million of related asset retirement obligations to Fieldwood Energy, LLC (“Fieldwood”). This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss on the sale. See Note 20 for discussion of Fieldwood’s related party affiliation with the Company.

In accordance with the terms of the sale, the Company agreed to guarantee on behalf of Fieldwood certain plugging and abandonment obligations associated with the Gulf Properties for a period of up to one year from the date of closing. The Company recorded a liability equal to the fair value of these guarantees, or $9.4 million, at the time the transaction closed. See Note 6 for additional discussion of the determination of the guarantee’s fair value. The guarantee did not limit the Company’s potential future payment obligations; however, Fieldwood agreed to indemnify the Company for any costs it incurred as a result of the guarantee and to use its best efforts to pay any amounts sought from the Company by the Bureau of Ocean Energy Management (“BOEM”) that arose prior to the expiration of the guarantee. The Company did not incur any costs as a result of this guarantee and was released from the obligation during the third quarter of 2015. Additionally, Fieldwood maintained, for a period of up to one year from the closing date, restricted deposits held in escrow for plugging and abandonment obligations associated with the Gulf Properties. In the first quarter of 2015, the Company received its share of such deposits, net of any amounts payable to Fieldwood, or $12.0 million, in accordance with the terms of the sale.

The company recorded revenues and expenses of $90.9 million and $63.7 million, respectively, through the date of the sale, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties which are included in the Predecessor Company’s accompanying consolidated statement of operations for the year ended December 31, 2014.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 following levels of the fair value hierarchy:

Level 1	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3	Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in each level of the hierarchy as of December 31, 2016 and 2015, as described below.

Level 1 Fair Value Measurements

Investments. The fair value of investments, consisting of assets attributable to the Company’s non-qualified deferred compensation plan, is based on quoted market prices. Investments are included in other current assets and other assets in the accompanying consolidated balance sheets.

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.

Mandatory Prepayment Feature - PGC Senior Secured Notes. In conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015, the Company issued the PGC Senior Secured Notes as discussed in Note 5. The PGC Senior Secured Notes were issued at a substantial discount, as discussed in Note 11 and Note 12, which resulted in the treatment of the mandatory prepayment feature as an embedded derivative that met the criteria to be bifurcated from its host contract and accounted for separately from the PGC Senior Secured Notes. Prior to Chapter 11 filings, the mandatory prepayment feature was recorded at fair value each reporting period based upon values determined through the use of discounted cash flow models of the PGC Senior Secured Notes both (i) with the mandatory prepayment feature and (ii) excluding the mandatory prepayment feature. Subsequent to the Chapter 11 filings in May 2016, the value of the mandatory repayment feature of $2.5 million was written off and is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period.

Level 3 Fair Value Measurements

Commodity Derivative Contracts. The Company had natural gas basis swaps outstanding on the Emergence Date and at December 31, 2015 and 2014. The fair value of the natural gas basis swaps was based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness through the use of a discounted cash flow model using non-exchange traded regional pricing information. Additionally, the Company applied a weighted average credit default risk rating factor for its counterparties or gave effect to its credit risk, as applicable, in determining the fair value of the commodity derivative contracts. The significant unobservable input that was used in the fair value measurement of the Company’s natural gas basis swaps was the estimate of future natural gas basis differentials. The fair value of the natural gas basis swaps and any purchases, gains/losses and settlements were insignificant for the Predecessor 2016 Period and for the years ended December 31, 2015 and 2014. No natural gas basis swaps were outstanding at December 31 2016.

Debt Holder Conversion Feature. The Predecessor Company’s Convertible Senior Unsecured Notes each contained a conversion option whereby, prior to Chapter 11 filings, the Convertible Senior Unsecured Notes holders had the option to convert the notes into shares of Company common stock. These conversion features were identified as embedded derivatives that met the criteria to be bifurcated from their host contracts and accounted for separately from the Convertible Senior Unsecured Notes. Subsequent to the Chapter 11 filings, the value of the debt holder conversion feature of $7.3 million was written off and is included in reorganization items in the accompanying statement of operations for the Predecessor 2016 Period.

The fair values of the holder conversion features were determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) recovery rate, (iv) hazard rate and (v) expected volatility. The significant unobservable input used in the fair value measurement of the conversion features was the hazard rate, an estimate of default probability. The significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion features atDecember 31, 2015are included in the table below.

Unobservable Input	Range					Weighted Average		Fair Value
								(In thousands)
Debt conversion feature hazard rate	114.0	%	–	135.2	%	119.2	%	$	29,355

See further discussion of the Convertible Senior Unsecured Notes at Note 11.

Guarantee. The Company guaranteed on behalf of Fieldwood certain plugging and abandonment obligations associated with the sale of its Gulf Properties from the date of closing until the Company was released from the guarantee in the third quarter of 2015. The significant unobservable input used in the fair value measurement of the guarantees was the estimate of future payments for plugging and abandonment of approximately $372.0 million, which was developed based upon third-party quotes and then-current actual costs. While in effect, the fair value of the guarantee was determined quarterly with changes in fair value recorded as an adjustment to the full cost pool. See Note 5 for discussion of the sale of the Gulf Properties. The fair value of the guarantee and any issuances and settlements were insignificant for the year ended December 31, 2014.

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, 2016 - Successor

	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Investments	$	7,541	$	—	$	—	$	—	$	7,541
	$	7,541	$	—	$	—	$	—	$	7,541
Liabilities
Commodity derivative contracts	$	—	$	29,714	$	—	$	—	$	29,714
	$	—	$	29,714	$	—	$	—	$	29,714

December 31, 2015 - Predecessor

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	85,524	$	—	$	(1,175	)	$	84,349
Investments	10,106		—		—		—			10,106
	$	10,106	$	85,524	$	—	$	(1,175	)	$	94,455
Liabilities
Commodity derivative contracts	$	—	$	—	$	1,748	$	(1,175	)	$	573
Debt holder conversion feature	—		—		29,355		—			29,355
Mandatory prepayment feature - PGC Senior Secured Notes	—		2,941		—		—			2,941
	$	—	$	2,941	$	31,103	$	(1,175	)	$	32,869

____________________

(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.    

Level 3 - Debt Holder Conversion Feature. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for debt holder conversion features (in thousands):

	Predecessor
	Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015
Beginning balance	$	29,355		$	—
Issuances	—			31,200
(Loss) gain on derivative holder conversion feature	(880		)	10,198
Conversions	(21,194		)	(12,043		)
Write off of derivative holder conversion feature to reorganization items	(7,281		)	—
Ending level 3 debt holder conversion feature balance	$	—		$	29,355

Prior to commencement of the Chapter 11 Proceedings, the fair values of the conversion features were determined quarterly with changes in fair value recorded as interest expense.

Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the years ended December 31, 2016, 2015 and 2014, 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 Successor Company measures the fair value of its New Convertible Notes using pricing that was readily available in the public market at December 31, 2016. The Successor Company measures the fair value of its New Building Note using a discounted cash flow analysis. The Predecessor Company also measured the fair value of its Senior Secured Notes and the Unsecured Notes using pricing that was readily available in the public market. The Company classifies these inputs as Level 2 in the fair value hierarchy. The estimated fair values and carrying values of the Company’s notes are as follows (in thousands):

	Successor				Predecessor
	December 31, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
New Convertible Notes	$	334,800	$	268,780	$	—	$	—
New Building Note	$	40,608	$	36,528	$	—	$	—
8.75% Senior Secured Notes due 2020	$	—	$	—	$	403,098	$	1,265,814
Senior Unsecured Notes
8.75% Senior Notes due 2020	$	—	$	—	$	39,740	$	389,232
7.5% Senior Notes due 2021	$	—	$	—	$	79,812	$	751,087
8.125% Senior Notes due 2022	$	—	$	—	$	57,749	$	518,693
7.5% Senior Notes due 2023	$	—	$	—	$	58,799	534,869
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022	$	—	$	—	$	44,199	$	78,290
7.5% Convertible Senior Notes due 2023	$	—	$	—	$	15,125	$	24,393

See Note 1 for additional information regarding the bankruptcy proceedings and Note 11 for discussion of the Company’s long-term debt.

Fair Value of Non-Financial Assets and Liabilities

See Note 2 for additional information regarding fair value adjustments for non-financial assets and liabilities resulting from the application of fresh start accounting and Note 9 for discussion of the Company’s impairment valuations.

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Accounts Receivable

12 Months Ended

Dec. 31, 2016

Receivables [Abstract]

Accounts Receivable

Accounts Receivable

A summary of accounts receivable is as follows (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
Oil, natural gas and NGL sales	$	42,631		$	61,140
Joint interest billing	17,338			60,403
Oil and natural gas services	736			2,417
Other	14,272			8,274
Total accounts receivable	74,977			132,234
Less: allowance for doubtful accounts	(880		)	(4,847		)
Total accounts receivable, net	$	74,097		$	127,387

The following table presents the balance and activity in the allowance for doubtful accounts for the Successor 2016 Period, the Predecessor 2016 Period and years ended December 31, 2015 and 2014 (in thousands):

	Successor					Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning balance	$	—	$	4,847		$	7,083		$	11,061
Additions charged to costs and expenses(1)	880		16,695			1,320			818
Deductions(2)	—		(751		)	(3,556		)	(4,796		)
Impact of fresh start accounting	—		(20,791		)	—			—
Ending balance	$	880	$	—		$	4,847		$	7,083

____________________

(1) The Predecessor 2016 Period includes an addition for a joint interest account receivable after a determination that future collection was doubtful.

(2) Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2015 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement and deductions in 2014 are related to the sale of the Gulf Properties.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
Oil and natural gas properties
Proved(1)	$	840,201		$	12,529,681
Unproved	74,937			363,149
Total oil and natural gas properties	915,138			12,892,830
Less accumulated depreciation, depletion and impairment	(353,030		)	(11,149,888		)
Net oil and natural gas properties capitalized costs	562,108			1,742,942
Land	5,100			14,260
Non-oil and natural gas equipment(2)	166,010			373,687
Buildings and structures(3)	88,603			227,673
Total	259,713			615,620
Less accumulated depreciation and amortization	(3,889		)	(123,860		)
Other property, plant and equipment, net	255,824			491,760
Total property, plant and equipment, net	$	817,932		$	2,234,702

____________________

(1) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $48.9 million at December 31, 2015.

(2) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $4.3 million at December 31, 2015.

(3) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $20.4 million at December 31, 2015.

In connection with the application of fresh start accounting as of October 1, 2016, the Company recorded fair value adjustments disclosed in Note 2. Accumulated depreciation, depletion and impairment was therefore eliminated as of that date.

Accumulated depreciation, depletion and impairment for the Predecessor Company oil and natural gas properties includes cumulative full cost ceiling limitation impairment of $8.2 billion at December 31, 2015.

During the Successor 2016 Period the Successor Company reduced the net carrying value of its oil and natural gas properties by $319.1 million and for the Predecessor 2016 Period, the Predecessor Company reduced the net carrying value of its oil and natural gas properties by $657.4 million, as a result of quarterly full cost ceiling analyses in the respective periods. The Company reduced the net carrying value of its oil and natural gas properties by $4.5 billion and $164.8 million during the years ended December 31, 2015 and 2014, respectively. See Note 9 for discussion of impairment of other property, plant and equipment.

The average rates used for depreciation and depletion of oil and natural gas properties were $7.82 per Boe for the Successor 2016 Period, $5.76 per Boe for the Predecessor 2016 Period, $10.67 per Boe in 2015 and $15.00 per Boe in 2014.

During the second and fourth quarters of 2015, the Company classified drilling and oilfield services assets having net book values of approximately $20.0 million and $16.0 million, respectively, as held for sale as a result of the Company’s decisions to discontinue substantially all drilling and oilfield services operations first in the Permian region and then companywide. A portion of these assets were disposed of during the third quarter of 2015, resulting in a loss recorded in other operating expenses in the accompanying consolidated statement of operations of $3.5 million for the year ended December 31, 2015.

The remaining $16.0 million in assets held for sale at December 31, 2015 were sold during 2016, resulting in insignificant (loss) gain on sale of assets recorded for the Successor 2016 period and the Predecessor 2016 period. No significant assets were classified as held for sale at December 31, 2016.

Drilling Carry Commitments

During the year ended December 31, 2014, the Company was party to an agreement with Repsol E&P USA, Inc. (“Repsol”), which contained a carry commitment to fund a portion of its future drilling, completing and equipping costs within areas of mutual interest. The Company recorded approximately $205.6 million for Repsol’s carry during the year ended December 31, 2014, which reduced the Company’s capital expenditures for the respective periods. Repsol fully funded its carry commitment in the third quarter of 2014.

Under the terms of an amended agreement with Repsol, the Company committed to drill 484 net wells in an area of mutual interest and to carry Repsol’s future drilling and completion costs in the amount of $1.0 million for each committed well that it did not drill, up to a maximum of $75.0 million in carry costs.  As of May 31, 2015, the Company had drilled 453 net wells under this arrangement and as a result, the Company was obligated under the agreement to carry a portion of Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled after that time in the area of mutual interest. The Company incurred approximately $6.2 million and $16.1 million in costs toward this obligation for the Predecessor 2016 Period and the year ended December 31, 2015, respectively. Effective June 6, 2016, the Bankruptcy Court issued orders allowing the Company to reject certain long-term contracts, including this drilling carry commitment. Repsol filed a bankruptcy claim for this commitment, which was settled by the Company for approximately $1.2 million.

Costs Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2016 (in thousands):

			Year Cost Incurred
	Total		2016		2015		2014		2013 and Prior
Property acquisition	$	71,171	$	7,390	$	18,959	$	34,770	$	10,052
Exploration(1)	20,459		2,123		10,578		4,678		3,080
Total costs incurred	$	91,630	$	9,513	$	29,537	$	39,448	$	13,132

____________________

(1) Includes $16.7 million of pipe inventory costs incurred ($2.1 million in 2016, $9.6 million in 2015 and $5.0 million in 2014 and prior years).

The Company expects to complete the majority of the evaluation activities within 10 years from the applicable date of acquisition, contingent on the Company’s capital expenditures and drilling program. In addition, the Company’s internal engineers evaluate all properties on at least an annual basis.

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Impairment

12 Months Ended

Dec. 31, 2016

Asset Impairment Charges [Abstract]

Impairment

Impairment

As deemed necessary based on events in 2016, 2015 and 2014, the Company analyzed various property, plant and equipment for impairment by comparing the carrying values of these 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 3.

Impairment consists of the following (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Full cost pool ceiling limitation(1)(2)(3)	$	319,087	$	657,392	$	4,473,787	$	164,779
Drilling assets(4)	—		3,511		37,646		27,428
Electrical transmission assets(5)	—		55,600		—		—
Midstream assets(6)	—		1,691		7,148		561
Other(7)	—		—		16,108		—
	$	319,087	$	718,194	$	4,534,689	$	192,768

____________________

(1) Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting. 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 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 impairments recorded in 2015 and the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes.

(3) Impairment in 2014 resulted from the divestiture of the Gulf Properties.

(4) Impairment recorded in the Predecessor 2016 Period and the year ended December 31, 2015, resulted from discontinued drilling operations in its Permian region which resulted in an impairment on certain drilling assets after determining their future use was limited. During 2014, the Company recorded a $24.3 million impairment on its drilling and oilfield services assets in the Permian region as a result of fulfilling its drilling obligation with the Permian Trust in 2014 and the downward trend in oil prices that began in the second half of 2014.

(5) Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage.

(6) Impairment in the Predecessor 2016 Period and the years ended December 31, 2015 and 2014 resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a carbon dioxide (“CO₂”) compressor station after determining that their future use was limited.

(7) Impairment recorded on other assets in 2015, includes a $15.4 million impairment on property located in downtown Oklahoma City, Oklahoma to adjust the carrying value of the property to the agreed upon sales price for which it was later sold in 2016.

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Accounts Payable and Accrued Expenses

12 Months Ended

Dec. 31, 2016

Payables and Accruals [Abstract]

Accounts Payable and Accrued Expenses

Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):

	Successor		Predecessor
	December 31,		December 31,
	2016		2015
Accounts payable and other accrued expenses	$	65,408	$	231,697
Accrued interest	648		73,320
Production payable	16,011		55,260
Payroll and benefits	33,606		42,728
Convertible perpetual preferred stock dividends	—		21,572
Drilling advances	844		2,295
Related party	—		1,545
Total accounts payable and accrued expenses	$	116,517	$	428,417

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Long-Term Debt

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Long-term debt consists of the following (in thousands):

	Successor		Predecessor
	December 31,		December 31,
	2016		2015
New First Lien Exit Facility	$	—	$	—
New Convertible Notes	268,780		—
New Building Note	36,528		—
Senior credit facility	—		—
8.75% Senior Secured Notes due 2020	—		1,265,814
Senior Unsecured Notes
8.75% Senior Notes due 2020	—		389,232
7.5% Senior Notes due 2021	—		751,087
8.125% Senior Notes due 2022	—		518,693
7.5% Senior Notes due 2023	—		534,869
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022	—		78,290
7.5% Convertible Senior Notes due 2023	—		24,393
Total debt	305,308		3,562,378
Less: current maturities of long-term debt	—		—
Long-term debt	$	305,308	$	3,562,378

On the Emergence Date, the balance outstanding under the senior credit facility of $449.2 million, par value of the Senior Secured Notes of $1.3 billion, par value of the Senior Unsecured Notes of $2.2 billion and par value of the Convertible Senior Unsecured Notes of $87.6 million were canceled upon emergence from bankruptcy and the Company entered into the New First Lien Exit Facility, issued New Convertible Notes and entered into the New Building Note as discussed further below. See Note 1 for additional information regarding the bankruptcy proceedings.

See Note 6 for the fair values and carrying values of the long-term debt outstanding at December 31, 2016 and 2015, respectively, and Note 2 for fresh start values calculated as of the Emergence Date. As of December 31, 2015, there were no amounts outstanding under the senior credit facility, and the carrying values of the senior notes were net of unamortized discounts, premiums and deferred costs of $342.6 million, and included the fair value of debt derivatives of $32.3 million. A non-cash charge to write off all of the related unamortized debt issuance costs and associated discounts and premiums of approximately $158.6 million and the fair value of associated debt derivatives of $9.8 million as of May 16, 2016, is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period, as discussed in Note 1 and Note 2.

Successor Company Indebtedness

New First Lien Exit Facility. As discussed in Note 1, on the Emergence Date, the Company entered into the New First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender.

The initial borrowing base under the New First Lien Exit Facility is $425.0 million. There are no scheduled borrowing base redeterminations until October 2018, followed by scheduled semiannual borrowing base redeterminations thereafter. The New First Lien Exit Facility matures on February 4, 2020. The outstanding borrowings under the New First Lien Exit Facility bear interest at a rate equal to, at the option of the Company, either (a) a base rate plus an applicable rate of 3.75% per annum or (b) LIBOR plus 4.75% per annum, subject to a 1.00% LIBOR floor. Interest on base rate borrowings 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 New First Lien Exit Facility. The Company has the right to prepay loans under the New First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans.

Furthermore, the New First Lien Exit Facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of the proved developed producing reserves and 95% of the PV-9 valuation of all proved reserves included in the most recently delivered reserve report of the Company, (ii) a first-priority perfected pledge of capital stock of each credit party and their respective wholly owned subsidiaries and (iii) a first-priority security interest in the cash, cash equivalents, deposit, securities and other similar accounts, and a first-priority perfected security interest in substantially all 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 New First Lien Exit Facility requires the Company to, (a) commencing with the first full fiscal quarter ending after the Protected Period, maintain a minimum proved developing producing reserves asset coverage ratio, measured as of the last day of each fiscal quarter, of 1.75 to 1.00 and (b) commencing with the first full fiscal quarter ending after the occurrence of the end of the Protected Period, maintain (i) a maximum consolidated total net leverage ratio, measured as of the last day of each fiscal quarter, (A) on or prior to December 31, 2018, of no greater than 3.50 to 1.00, and (B) any fiscal quarter ending on or after March 31, 2019, of no greater than 3.00 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the last day of each fiscal quarter, of no less than 2.00 to 1.00. Such financial covenants are subject to customary cure rights.

The New First Lien Exit Facility contains customary affirmative and negative covenants, including compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments and other customary covenants.

The Company had no amounts outstanding under the New First Lien Exit Facility at December 31, 2016 and $8.6 million in outstanding letters of credit, which reduce availability under the New First Lien Exit Facility on a dollar-for-dollar basis.

The Company subsequently refinanced the New First Lien Exit Facility in February 2017. See Note 21 for additional discussion.

New 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 New Convertible Notes, which do not bear regular interest and will mature and mandatorily convert into New Common Stock on October 4, 2020, unless repurchased, redeemed or converted prior to that date. The New Convertible Notes were recorded at fair value of $445.7 million upon implementation of fresh start accounting. As the associated premium of $163.9 million was deemed significant to the principal amount of the New Convertible Notes, it was recorded in additional paid in capital in the consolidated balance sheet at December 31, 2016. Upon the occurrence of certain events, including any acceleration, repayment or prepayment of the New Convertible Notes (including any optional redemption), the Company will be required to pay a make-whole amount of $0.783478 for each $1.00 in principal amount of New Convertible Notes repaid or prepaid in accordance with the provisions of the associated indenture.

The New Convertible Notes are initially convertible at a conversion rate of 0.05330841 shares of New Common Stock per $1.00 principal amount of New Convertible Notes, which represents, in the aggregate, approximately 15.0 million shares of the New Common Stock. The conversion rate for the New Convertible Notes is subject to customary anti-dilution adjustments. In addition, upon the occurrence of certain events, including any acceleration, repayment or prepayment of the New Convertible Notes (including any optional redemption), the conversion rate will be automatically adjusted such that the New Convertible Notes convert into the same percentage of New Common Stock before and after such event.

The New Convertible Notes are convertible at the option of the holders at any time up to, and including, the business day immediately preceding the maturity date. In addition, the Company is required to convert all outstanding New Convertible Notes upon the earliest to occur of the following: (i) any bona fide arm’s length issuance by the Company of New Common Stock to third parties for cash with (a) a total issuance size that is greater than or equal to $100.0 million and (b) a per-share price greater than or equal to $34.16; (ii) 30 days’ written notice to the Company to convert the New Convertible Notes from holders of at least a majority in aggregate principal amount of the New Convertible Notes then outstanding; (iii) the average of the last reported sale prices of the New Common Stock over a 30 consecutive trading day period is 50% greater than $34.16; (iv) any bona fide refinancing of the New First Lien Exit Facility after a determination by the post-emergence board of directors in good faith that: (a) such refinancing provides for terms that are materially more favorable to the Company and (b) the causing of a conversion is not the primary purpose of such refinancing; (v) any change of control transaction; or (vi) the maturity date. Upon conversion, the Company will deliver shares of New Common Stock equal to the conversion rate, together with a cash payment in lieu of delivering any fractional share of New Common Stock issuable upon conversion, based on the last reported sale price of the New Common Stock on the relevant conversion date. During the Successor 2016 Period, holders of approximately $13.0 million in aggregate principal amount of the New Convertible Notes exercised conversion options applicable to those notes, resulting in the issuance of approximately 0.7 million shares of New Common Stock.

The Company may redeem for cash all or part of the New Convertible Notes at any time prior to the maturity date, at a redemption price equal to 100% of the principal amount of such New Convertible Notes to be redeemed, as increased by the make-whole amount. With respect to any New Convertible Notes selected for redemption that are converted following a redemption notice, the conversion rate will be automatically adjusted such that the New Convertible Notes convert into the same percentage of New Common Stock before and after such redemption notice.

The Company’s obligations pursuant to the New Convertible Notes are fully and unconditionally guaranteed, jointly and severally, by each of the Guarantors of the New First Lien Exit Facility. Following the occurrence of certain events, the Company would be required to secure $100.0 million of the New Convertible Notes, which amount may be increased to the full outstanding principal amount of the New Convertible Notes, including any applicable make-whole amount, in accordance with the provisions of the New Convertible Notes Indenture (the “Springing Lien”). The Springing Lien will be a second priority lien on the same collateral securing the New First Lien Exit Facility.    

The remaining outstanding New Convertible Notes were converted into shares of New Common Stock as a result of the Company’s entry into the refinanced credit facility on February 10, 2017, as discussed in Note 21.

New Building Note. As discussed in Note 1, on the Emergence Date, the Company entered into the New Building Note, which has a principal amount of $35.0 million and is secured by first priority mortgage on the Company’s headquarters facility and certain other non-oil and gas real property. The New Building Note was recorded at fair value of $36.6 million upon implementation of fresh start accounting. Interest is payable on the New Building Note at 6% per annum for the first year following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. The effective interest rate was 10.9% for the New Building Note at December 31, 2016. Interest is payable in kind from the Emergence Date through the earlier of September 30, 2020, 46 months from the Emergence Date or 90 days after the refinancing or repayment of the New First Lien Exit Facility and thereafter in cash. The New Building Note matures on October 4, 2021. On the Emergence Date, pursuant to the Plan, certain holders of the Unsecured Senior Notes purchased the New Building Note for $26.8 million in cash, net of certain fees and expenses.

Predecessor Company Indebtedness

Senior Credit Facility. The terms of the senior credit facility contained certain financial covenants, including maintenance of agreed upon levels for the (a) ratio of total secured debt under the senior credit facility to earnings before interest, taxes, depreciation and amortization (“EBITDA”), which could not exceed 2.00:1.00 at each quarter end and (b) ratio of current assets to current liabilities, which was required to be at least 1.0:1.0 at each quarter end. For the purpose of the current ratio calculation, any amounts available to be drawn under the senior credit facility were included in current assets and unrealized assets and liabilities that resulted from mark-to-market adjustments on the Company’s commodity derivative contracts were disregarded. The senior credit facility matured by its terms on the earlier of March 2, 2020 and 91 days prior to the earliest date of any maturity under or mandatory offer to repurchase the Company’s then outstanding notes.

The senior credit facility also contained various covenants that limited the ability of the Company and certain of its subsidiaries to: grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. The terms of the senior credit facility allowed the Company to redeem or purchase outstanding Senior Unsecured Notes for up to $275.0 million in cash subject to certain limitations. Additionally, the senior credit facility limited the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions.

The obligations under the senior credit facility were guaranteed by certain Company subsidiaries and were required to be secured by first priority liens on all shares of capital stock of certain of the Company’s material present and future subsidiaries, all of the Company’s intercompany debt, and certain of the Company’s other assets, including proved oil, natural gas and NGL reserves representing at least 80.0% of the discounted present value (as defined in the senior credit facility) of proved oil, natural gas and NGL reserves of the Company.

At the Company’s election, interest under the senior credit facility, was determined by reference to (a) LIBOR plus an applicable margin between 1.750% and 2.750% per annum or (b) the “base rate,” which is the highest of (i) the federal funds rate plus 0.5%, (ii) the prime rate published by Royal Bank of Canada under the senior credit facility or (iii) the one-month Eurodollar rate (as defined in the senior credit facility) plus 1.00% per annum, plus, in each case under scenario (b), an applicable margin between 0.750% and 1.750% per annum. Interest was payable quarterly for base rate loans and at the applicable maturity date for LIBOR loans, except that if the interest period for a LIBOR loan was six months or longer, interest was paid at the end of each three-month period. Quarterly, the Company paid commitment fees assessed at annual rates of 0.5% on any available portion of the senior credit facility.

On March 11, 2016, the administrative agent notified the Company that the lenders had elected to reduce the borrowing base to $340.0 million from $500.0 million pursuant to a special redetermination. On April 20, 2016, the Company submitted for consideration by its lenders additional properties to serve as collateral under the senior credit facility to support a borrowing base of $500.0 million. On May 11, 2016, in exchange for waivers from the requisite percentage of lenders with respect to certain specified defaults and events of defaults under the senior credit facility, the Company permanently repaid $40.0 million of borrowings to the lenders, which payment correspondingly reduced the lenders’ commitments.

Senior Secured Notes. The Company issued $1.25 billion of 8.75% Senior Secured Notes due 2020 in June 2015. Net proceeds from the issuance were approximately $1.21 billion after deducting offering expenses, a portion of which was used to repay amounts outstanding at that time under the Company’s senior credit facility.

Additionally, the Company issued $78.0 million par value of the PGC Senior Secured Notes in conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015. Because the PGC Senior Secured Notes were issued as partial consideration for the acquisition and termination, these notes were recorded at fair value of approximately $50.3 million, which included mandatory prepayment feature liabilities and a discount. Fair value at issuance was determined based upon the then-current market value of the Senior Secured Notes. The unamortized portions of the discount and the carrying value of the mandatory prepayment feature as of the date of the Chapter 11 filings, May 16, 2016, were written off to reorganization items on the accompanying consolidated statement of operations for the Predecessor 2016 Period as discussed in Note 1.

The Company accrued interest on its Senior Secured Notes at a fixed rate of 8.75% prior to the Chapter 11 filings, with no interest accrued subsequent to the filings. The Senior Secured Notes were by their terms redeemable, in whole or in part, prior to their maturity at specified redemption prices and were jointly and severally guaranteed unconditionally, in full, on a second-priority secured basis by certain of the Company’s wholly owned subsidiaries.

The Senior Secured Notes were secured by second-priority liens on all of the Company’s assets that secured the senior credit facility on a first-priority basis; provided, however, the security interest in those assets that secured the Senior Secured Notes and the guarantees were contractually subordinated to liens thereon that secured the credit facility and certain other permitted indebtedness. Consequently, the Senior Secured Notes and the guarantees were effectively subordinated to the credit facility and such other indebtedness to the extent of the value of such assets.

Pursuant to the indenture, the Senior Secured Notes by their terms matured on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeded $100.0 million, the Senior Secured Notes would mature on October 16, 2019. See further discussion of the mandatory prepayment feature at Note 6 and Note 12, which with respect to the PGC Senior Secured Notes was an embedded derivative that was accounted for separately from these notes, and was written off to reorganization items on the accompanying consolidated statement of operations for the Predecessor 2016 Period as discussed in Note 1.

The indenture governing the Senior Secured Notes contained covenants that restricted the Company’s ability to pay dividends, incur indebtedness, create liens, enter into consolidations or mergers, purchase or redeem stock or subordinated or unsecured indebtedness, dispose of or transfer certain assets, transact with related parties, make investments and refinance certain indebtedness, among other actions. These indentures were canceled upon the Company’s emergence from Chapter 11. See

Note 1 for additional details about the Company’s Bankruptcy Petitions and the Chapter 11 proceedings.

Senior Unsecured Notes. The Company accrued interest on its Senior Unsecured Notes at a fixed rate through the date of the Chapter 11 filings, with no interest accrued subsequent to the filings. Certain of the Senior Unsecured Notes were issued at a discount or a premium. Prior to the Chapter 11 filings, the discount or premium was amortized to interest expense over the term of the respective series of Senior Unsecured Notes. The unamortized portions of the discount or premium as of the date of the Chapter 11 filings, May 16, 2016, were written off to reorganization items on the accompanying consolidated statement of operations for the Predecessor 2016 Period as discussed in Note 1.

Each of the indentures governing the Company’s Senior Unsecured Notes contained covenants that restricted the Company’s ability to pay dividends, incur indebtedness, make investments, sell certain assets, purchase certain assets, transact with related parties and enter into consolidations or mergers. These indentures were canceled upon the Company’s emergence from Chapter 11.

Convertible Senior Unsecured Notes. The Convertible Senior Unsecured Notes were issued in conjunction with exchanges and repurchases of Senior Unsecured Notes that took place in August and October 2015. The transactions were determined to be an extinguishment of each of the Senior Unsecured Notes exchanged. As such, the newly-issued Convertible Senior Unsecured Notes were recorded at fair value on the date of issuance. The Convertible Senior Unsecured Notes were guaranteed by the same Guarantors that guaranteed the Senior Unsecured Notes and were subject to covenants and bore payment terms substantially identical to those of the corresponding series of Senior Unsecured Notes of similar tenor, other than the conversion features, described further below, and the extension of the final maturity by one day. The Company accrued interest on its Convertible Senior Unsecured Notes at a fixed rate through the date of the Chapter 11 filings, with no interest accrued subsequent to the filings.

During the Predecessor 2016 Period, holders of $200.5 million aggregate principal amount ($67.4 million net of discount and including holders’ conversion feature) of 8.125% Convertible Senior Notes due 2022 and $31.6 million aggregate principal amount ($10.4 million net of discount and holders’ conversion feature) of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 84.4 million shares of Company common stock and aggregate cash payments of $33.5 million for accrued interest and early conversion payments. The conversions resulted in a gain on extinguishment of debt totaling $41.3 million, including the write off of $4.3 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for the Predecessor 2016 Period.

During the year ended December 31, 2015, holders of $186.6 million aggregate principal amount ($54.4 million net of discount and including holders’ conversion feature) of 8.125% Convertible Senior Notes due 2022 and $68.7 million aggregate principal amount ($19.3 million net of discount and holders’ conversion feature) of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 92.8 million shares of Company common stock and aggregate cash payments of $30.5 million for accrued interest and early conversion payments. The conversions resulted in a gain on extinguishment of debt totaling $6.1 million, including the write off of $5.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for year ended December 31, 2015.

Maturities of Long-Term Debt

As of December 31, 2016, $268.8 million of long-term debt will contractually mature in 2020 and $35.0 million, plus any unpaid interest on the New Building Note, will mature in 2021.

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Derivatives

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

The Company has not designated any of its derivative contracts as hedges for accounting purposes. The Company records all derivative contracts at fair value. Changes in derivative contract fair values are recognized in earnings.

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. The Company seeks to manage this risk through the use of commodity derivative contracts, which allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. 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. Cash settlements and valuation gains and losses on commodity derivative contracts are included in loss (gain) on derivative contracts in the consolidated statements of operations. Commodity derivative contracts are settled on a monthly or quarterly basis. Derivative assets and liabilities arising from the Company’s commodity derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheets. At December 31, 2016, the Company’s commodity derivative contracts consisted of fixed price swaps under which the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

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 settlements of contracts prior to their contractual maturity (“early settlements”) after the Chapter 11 filings occurred, resulting in $17.9 million of cash receipts.

The Company recorded gain on commodity derivative contracts of $73.1 million and $334.0 million for the years ended December 31, 2015 and 2014, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(327.7) million and $32.3 million, respectively. Included in the net cash payments for 2014 are $69.9 million of cash payments related to early settlements primarily as a result of the sale of the Gulf Properties in February 2014.

Derivatives Agreements with Royalty Trusts. During the years ended December 31, 2015 and 2014, the Company was party to derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts entered into by the Company with third parties. The derivatives agreements with the Mississippian Trust I and the Mississippian Trust II contained commodity derivative contracts that covered volumes of oil and natural gas production through December 31, 2015, and the derivatives agreement with the Permian Trust contained commodity derivative contracts that covered volumes of oil production through March 31, 2015. All activity related to the contracts underlying the derivatives agreements with the Royalty Trusts have been included in the Company’s consolidated derivative disclosures.

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, 2016, 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 New First Lien Exit Facility. The Company is not required to post additional collateral under its commodity derivative contracts as certain of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s New First Lien Exit Facility. 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 New First Lien Exit Facility and senior credit facility (in thousands):

December 31, 2016 - Successor

	Gross Amounts		Gross Amounts Offset		Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	—	$	—	$	—	$	—		$	—
Derivative contracts - noncurrent	—		—		—		—			—
Total	$	—	$	—	$	—	$	—		$	—
Liabilities
Derivative contracts - current	$	27,538	$	—	$	27,538	$	(27,538	)	$	—
Derivative contracts - noncurrent	2,176		—		2,176		(2,176		)	—
Total	$	29,714	$	—	$	29,714	$	(29,714	)	$	—

December 31, 2015 - Predecessor

	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Liabilities
Derivative contracts - current	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—

At December 31, 2016, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2017 - December 2017	3,285	$	52.24
January 2018 - December 2018	1,825	$	55.34

Natural Gas Price Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2017 - December 2017	32,850	$	3.20
January 2018 - December 2018	3,650	$	3.12

Predecessor Debt - Embedded Derivatives

Debt Holder Conversion Feature. As discussed further in Note 6 and Note 11, the Convertible Senior Unsecured Notes contained a conversion feature that was exercisable at the holders’ option. This conversion feature was identified as an embedded derivative as the feature (i) possessed economic characteristics that were not clearly and closely related to the economic characteristics of the host contract, the Convertible Senior Unsecured Notes, and (ii) separate, stand-alone instruments with the same terms would have qualified as derivative instruments. As such, the holders’ conversion feature was bifurcated and accounted for separately from the Convertible Senior Unsecured Notes. The holders’ conversion feature was recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statement of operations for the Predecessor 2016 Period and the year ended December 31, 2015. Subsequent to the Chapter 11 filings, the value of the debt holder conversion features was written off and is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period.

Mandatory Prepayment Feature - PGC Senior Secured Notes. As discussed further in Note 6 and Note 11, the Senior Secured Notes contained a mandatory prepayment feature that was triggered if the outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeded $100.0 million on October 15, 2019. With respect to the PGC Senior Secured Notes, which were issued at a substantial discount, this mandatory prepayment feature was identified as an embedded derivative as the feature (i) possessed economic characteristics that were not clearly and closely related to the economic characteristics of the host contract, the PGC Senior Secured Notes, and (ii) separate, stand-alone instruments with the same terms would have qualified as derivative instruments. As such, the mandatory prepayment feature contained in the PGC Senior Secured Notes was bifurcated and accounted for separately from those notes. The mandatory prepayment feature contained in the PGC Senior Secured notes was recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statements of operations for the Predecessor 2016 Period and the year ended December 31, 2015. Subsequent to the Chapter 11 filings, the value of the mandatory prepayment feature was written off and is included in reorganization items in the accompanying consolidated statement of operations for the Predecessor 2016 Period.

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):

		Successor			Predecessor
		December 31,			December 31,
Type of Contract	Balance Sheet Classification	2016			2015
Derivative assets
Oil price swaps	Derivative contracts - current	$	—		$	68,224
Oil collars—three way	Derivative contracts - current	—			17,300
Derivative liabilities
Oil price swaps	Derivative contracts - current	(13,395		)	—
Natural gas price swaps	Derivative contracts - current	(14,143		)	—
Natural gas basis swaps	Derivative contracts - current	—			(1,748		)
Debt holder conversion feature	Current maturities of long-term debt	—			(29,355		)
Mandatory prepayment feature - PGC Senior Secured Notes	Current maturities of long-term debt	—			(2,941		)
Oil price swaps	Derivative contracts - noncurrent	(2,105		)	—
Natural gas price swaps	Derivative contracts - noncurrent	(71		)	—
Total net derivative contracts		$	(29,714	)	$	51,480

See Note 6 for additional discussion of the fair value measurement of the Company’s derivative contracts and Note 11 for discussion of the debt holder conversion and mandatory prepayment features.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The following table presents the balance and activity of the asset retirement obligations (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning balance	$	92,413		$	103,578		$	54,402		$	424,117
Liability incurred upon acquiring and drilling wells	121			505			1,662			4,968
Revisions in estimated cash flows(1)	12,397			—			44,060			(5,848		)
Liability settled or disposed in current period(2)	(540		)	(36,979		)	(1,023		)	(377,927		)
Accretion	2,090			4,365			4,477			9,092
Impact of fresh start accounting	—			20,944			—			—
Ending balance	106,481			92,413			103,578			54,402
Less: current portion	66,154			65,678			8,399			—
Asset retirement obligations, net of current	$	40,327		$	26,735		$	95,179		$	54,402

____________________

(1) Revisions for the Successor 2016 Period and the year ended December 31, 2015 relate primarily to changes in estimated well lives.

(2) Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016. Liability settled or disposed for the year ended December 31, 2014, includes $366.0 million associated with the Gulf Properties sold in February 2014. For further discussion of the sale of properties see Note 5.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Employee Termination Benefits. Certain employees received termination benefits, including severance and accelerated stock vesting, upon separation of service from the Company during the years ended December 31, 2016, 2015 and 2014. Employee termination benefits were $12.3 million for the Successor 2016 Period, with approximately $5.7 million accrued at December 31, 2016 for payment in the first quarter of 2017 and $18.4 million for the Predecessor 2016 Period, primarily as a result of reductions in workforce. For the years ended December 31, 2015 and 2014, employee termination benefits were $12.5 million and $8.9 million, respectively, primarily as a result of a reduction in workforce and executives’ separation from employment, and the sale of the Gulf Properties.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which depend on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company enters into commodity derivative arrangements in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 12 for the Company’s open oil and natural gas commodity derivative contracts.

The Company historically has depended on cash flows from operating activities and, as necessary, borrowings under its senior credit facility to fund its capital expenditures. Based on its cash balances, cash flows from operating activities and net borrowing availability under the New First Lien Exit Facility, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2017; however, oil or natural gas prices decline from current levels, they would have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. The Company subsequently refinanced the New First Lien Exit Facility in February 2017. See Note 21 for additional discussion.

Litigation and Claims

Chapter 11 Proceedings

The Plan in the Chapter 11 Cases discharged claims, including claims related to litigation proceedings against the Company that arose before such date. The Plan generally treated such claims as general unsecured claims that will receive only partial distribution of the amounts of consideration set aside for such claims under the Plan, which consists of cash, shares of New Common Stock and Warrants, once their amounts, if any, are finally determined by the Bankruptcy Court or otherwise. The effectiveness of the Plan also resulted in the release of certain claims held by the Company against various parties to the restructuring and related parties, including certain of the Company’s current and former officers and former directors. See Note 1 for further discussion about the Company’s Bankruptcy Petitions and the Chapter 11 Cases.

To the extent that a claim related to a pre-petition proceeding or action is not characterized as a pre-petition general unsecured claim, the Company does not believe that such claim would be material, although the anticipated resolution of any such proceeding or action is inherently unpredictable.

Successor Claims

On October 14, 2016, Lisa West and Stormy Hopson filed a class action complaint in the United States District Court for the Western District of Oklahoma against SandRidge Exploration and Production, LLC, among other defendants. In their complaint, plaintiffs assert various tort claims seeking relief for damages allegedly incurred by the plaintiffs and the proposed class for injury to property and for the purchase of insurance policies allegedly needed by the plaintiffs and the proposed class for seismic activity allegedly caused by the defendants’ operation of wastewater disposal wells. An estimate of reasonably probable losses associated with this action cannot be made at this time. The Company had not established any reserves relating to this action.

Predecessor Claims

As previously disclosed, on February 4, 2015, the staff of the Securities and Exchange Commission (the “SEC”) Enforcement Division in Washington, D.C., notified the Company that it had commenced an informal inquiry concerning the Company’s accounting for, and disclosure of, its CO₂ delivery shortfall penalties under the terms of the Gas Treating and CO₂ Delivery Agreement, dated June 29, 2008, between SandRidge Exploration and Production, LLC, and Oxy USA Inc. Additionally, the Company received a letter from an attorney for a former employee at the Company (the “Former Employee”). In the letter, the attorney alleged, among other things, that the Former Employee had been terminated because he had objected to the levels of oil and gas reserves disclosed by the Company in its public filings. Over 85% of such reserves were calculated by an independent petroleum engineering firm. The Audit Committee of the Company’s pre-emergence Board of Directors retained an independent law firm to review the Former Employee’s allegations and the circumstances of the Former Employee’s termination. In addition, the Company reported the Former Employee’s allegations to the SEC staff, which thereafter issued two subpoenas to the Company relating to the Former Employee’s allegations. Counsel for the Audit Committee responded to both of these subpoenas. During the course of the above inquiries, the SEC issued a subpoena to the Company seeking documents relating to employment-related agreements between the Company and certain employees. The Company cooperated with this inquiry and, after discussion with the staff, the Company sent corrective letters to certain current and former employees who had entered into agreements containing language that may have been inconsistent with SEC rules prohibiting a company from impeding an individual from communicating directly with the SEC about possible securities law violations. The Company also updated its Code of Conduct and other relevant policies.

On June 16, 2016, the SEC filed a proof of claim in the Company’s Chapter 11 Cases in the amount of $1.2 million as a result of the SEC staff’s inquiry concerning employment-related agreements. As a result of the SEC’s proof of claim, the Company established a $1.4 million reserve for this matter.

On December 20, 2016, the Company and the SEC settled both the inquiry involving employment-related agreements and the inquiry involving the termination of the Former Employee. Pursuant to the settlement agreement, the Company agreed to pay a fine in the amount of $1.4 million. The fine will be treated as a general unsecured claim under the Plan and, as such, the Company expects to pay approximately $0.1 million to resolve these two inquiries. The Company neither admitted nor denied any violations as part of the settlement agreement. Additionally, the SEC informed the Company that as part of the settlement agreement, the SEC would not be recommending charges against the Company with regard to its pre-petition disclosures of the CO2 delivery shortfall penalties under the Company’s agreement with Oxy USA Inc., or with regard to the Company’s pre-petition processes and disclosures related to its reserves.

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.

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Equity

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Equity

Equity

Successor Equity

New Common Stock. As discussed in Note 1, on the Emergence Date, the Company issued an aggregate of approximately 18.9 million shares of its New Common Stock, par value $0.001 per share, to the holders of allowed claims, as defined in the Plan, and approximately 0.4 million shares of New Common Stock were reserved for future distributions under the Plan. Additionally, during the Successor 2016 Period, voluntary conversions of New Convertible Notes resulted in the issuance of New Company Stock. See Note 11 for further discussion of the New Convertible Notes.

Warrants. As discussed in Note 1, on the Emergence Date, the Company issued approximately 4.9 million Series A Warrants, 4.5 million of which was issued immediately upon emergence and 2.1 million Series B Warrants, 1.9 million of which was issued immediately upon emergence, that were initially exercisable for one share of New 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, to certain holders of general unsecured claims as defined in the Plan. The Warrants are exercisable from the Emergence Date until October 4, 2022. The Warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions. 

Unregistered Sales of Equity Securities. The Company relied on Section 1145(a)(1) of the Bankruptcy Code as an exemption from the registration requirements of the Securities Act for the issuance of the New Common Stock, the New Convertible Notes and the Warrants. Section 1145(a)(1) of the Bankruptcy Code exempts the offer and sale of securities under a plan of reorganization from registration under Section 5 of the Securities Act and state laws if three principal requirements are satisfied:

• the securities must be issued under a plan of reorganization by the debtor, its successor under a plan, or an affiliate participating in a joint plan of reorganization with the debtor;

• the recipients of the securities must hold a claim against, an interest in, or a claim for administrative expense in the case concerning the debtor or such affiliate; and

• the securities must be issued either (a) in exchange for the recipient’s claim against, interest in or claim for administrative expense in the case concerning the debtor or such affiliate or (b) principally in such exchange and partly for cash or property.

Treasury Stock. The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and withhold a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The number of shares withheld for taxes and the associated value of those shares for the Successor 2016 Period were insignificant. These shares were accounted for as treasury stock when withheld, and then immediately retired.

Predecessor Equity

Preferred Stock. As discussed in Note 1, on the Emergence Date the Company’s authorized 7.0% and 8.5% convertible perpetual preferred stock was canceled and released under the Plan without receiving any recovery on account thereof.

Each outstanding share of convertible perpetual preferred stock was convertible at the holder’s option at any time into shares of the Company’s common stock at the specified conversion rate, subject to customary adjustments in certain circumstances.Each holder was entitled to an annual dividend payable semi-annually in cash, common stock or a combination thereof, at the Company’s election. The Company could cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the prevailing conversion rate dependent on certain factors, including the Company’s stock trading above specified prices for a set period. The convertible perpetual preferred stock was not redeemable by the Company at any time. For the year ended December 31, 2015, approximately 0.2 million shares were converted into approximately 3.0 million shares of the Predecessor Company’s common stock. The following table summarizes information about each series of the Predecessor Company’s convertible perpetual preferred stock outstanding at December 31, 2015:

	Convertible Perpetual Preferred Stock
	8.5%		7.0%
Liquidation preference per share	$	100.00	$	100.00
Annual dividend per share	$	8.50	$	7.00
Conversion rate per share to common stock	12.4805		12.8791

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.

In the first quarter of 2016, prior to the February semi-annual dividend payment date, the Company announced the suspension of the semi-annual dividend on its 8.5% convertible perpetual preferred stock. The Company suspended payment of the cumulative dividend on its 7.0% convertible perpetual preferred stock during the third quarter of 2015. The final dividend payment for the previously outstanding 6.0% convertible preferred stock was made during 2014, as it fully converted to common stock in 2014. 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.

Preferred stock dividend payments and accruals for the Company’s 8.5%, 7.0% and 6.0% convertible perpetual preferred stock are as follows (in thousands):

	Predecessor
	Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
8.5% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	11,262	$	22,525
Dividends satisfied in shares of common stock(1)	$	—	$	11,262	$	—
Accrued dividends at period end	$	—	$	8,447	$	8,447
Dividends in arrears	$	11,262	$	—	$	—
7.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	—	$	21,000
Dividends satisfied in shares of common stock(2)	$	—	$	10,500	$	—
Accrued dividends at period end	$	—	$	13,125	$	2,625
Dividends in arrears	$	21,000	$	10,500	$	—
6.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	—	$	12,000
Accrued dividends at period end	$	—	$	—	$	—

____________________

(1) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 18.6 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, ($3.58 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

(2) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 5.7 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, ($2.23 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

Paid and unpaid dividends included in the calculation of (loss applicable) income available to the Company’s common stockholders and the Company’s basic (loss) earnings per share calculation for the Predecessor 2016 Period and years ended December 31, 2015 and 2014 are presented in the accompanying consolidated statements of operations.

See Note 19 for discussion of the Company’s (loss) earnings per share calculation.

Common Stock. As discussed in Note 1, on the Emergence Date the Company’s authorized common stock was canceled and released under the Plan without receiving any recovery on account thereof.

In June 2015, the Company's stockholders approved an amendment to the Company's Certificate of Incorporation, to increase the number of shares of capital stock the Company is authorized to issue from 850.0 million (800.0 million shares of common stock and 50.0 million shares of preferred stock), par value $0.001 to 1.85 billion (1.80 billion shares of common stock and 50.0 million shares of preferred stock), par value $0.001. The Company had 2.1 million shares of common stock held in treasury at December 31, 2015.

Redemption of Senior Unsecured Notes. During the year ended December 31, 2015, the Company issued approximately 28.0 million shares of common stock in exchange for $50.0 million in Senior Unsecured Notes. See Note 11 for additional discussion of the redemption of Senior Unsecured Notes.

Conversions of Convertible Senior Unsecured Notes. During the Predecessor 2016 Period and year ended December 31, 2015, the Company issued approximately 84.4 million and 92.8 million shares, respectively, of common stock upon the exercise of conversion options by holders of approximately $232.1 million and $255.3 million in par value, respectively, of the Convertible Senior Unsecured Notes. The Company recorded the issuance of common shares at fair value on the various dates the exchanges occurred. See Note 11 for additional discussion of the Convertible Senior Unsecured Notes transactions.

See Note 16 for discussion of the Company’s share-based compensation.

Treasury Stock. 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.

	Predecessor
	Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Number of shares withheld for taxes	1,122		1,872		1,034
Value of shares withheld for taxes	$	44	$	2,428	$	6,373

Prior to the Emergence Date, shares of Predecessor Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan were accounted for as treasury shares. These shares were not included as outstanding shares of common stock for accounting purposes, and were canceled on the Emergence Date. No further matching contributions will be made to the non-qualified deferred compensation plan by the Successor Company.

Stockholder Receivable. The Predecessor Company was party to a settlement agreement relating to a third-party claim against its former CEO under Section 16(b) of the Securities Exchange Act of 1934, as amended. At December 31, 2015, the remaining $1.3 million receivable related to this settlement was classified as a component of additional paid-in capital in the accompanying consolidated balance sheet. In accordance with the Plan, the remaining balance of this receivable was fully discharged on the Emergence Date.

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Share-Based Compensation

12 Months Ended

Dec. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

Share-Based Compensation

As discussed in Note 1, the Predecessor Company’s common stock was canceled and New Common Stock was issued on the Emergence Date. Accordingly, the Predecessor Company's then existing share-based compensation awards were also canceled, which resulted in the recognition of any previously unamortized expense related to the canceled 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.Pursuant to terms of the Plan, the SandRidge Energy, Inc. 2016 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) became effective on the Emergence Date.

The Successor Company’s board of directors or any committee duly authorized thereby, will administer the Omnibus Incentive Plan. The committee has broad authority under the Omnibus Incentive Plan to, among other things: (i) select participants; (ii) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards; and (iii) establish the terms and conditions of awards, including the price (if any) to be paid for the shares or the award.

Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors, employees of the Successor Company or any of its affiliates, and certain consultants and advisors to the Successor 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 New Common Stock, as well as certain cash-based awards.

The maximum number of shares of New Common Stock that may be issued or transferred pursuant to awards under the Omnibus Incentive Plan is approximately 4.6 million. If any stock option or other stock-based award granted under the Omnibus Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of New Common Stock underlying any unexercised award shall again be available for the purpose of awards under the Omnibus Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of New Common Stock awarded under the Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the Omnibus Incentive Plan. Any award under the Omnibus Incentive Plan settled in cash shall not be counted against the maximum share limitation.

As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the Omnibus Incentive Plan and any outstanding awards, as well as the exercise or purchase prices of awards, and performance targets under certain types of performance-based awards, are subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Company’s stockholders.

Restricted Common Stock Awards. During October 2016, awards for approximately 1.4 million shares of restricted stock were granted under the Omnibus Incentive Plan. These restricted shares will vest over a three year period. The Successor Company recognized share-based compensation expense of $6.6 million, net of $0.3 million capitalized, for the Successor 2016 Period. Additionally, share-based compensation expense for the Successor 2016 Period includes $4.3 million for the accelerated vesting of 0.2 million restricted common stock awards related to the Successor Company’s reduction in workforce during the fourth quarter of 2016. 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	—		$	—
Granted	1,448		$	24.32
Vested	(14	)	$	24.32
Forfeited / Canceled	(27	)	$	24.32
Unvested restricted shares outstanding at December 31, 2016	1,407		$	24.32

As of December 31, 2016, the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $27.1 million. The remaining weighted-average contractual period over which this compensation cost may be recognized is 2.8 years. The Successor Company’s restricted stock awards are equity-classified awards.

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, 2013	7,643		$	6.92
Granted	6,367		$	6.17
Vested	(3,432	)	$	7.04
Forfeited / Canceled	(2,022	)	$	6.60
Unvested restricted shares outstanding at December 31, 2014	8,556		$	6.39
Granted	2,928		$	0.88
Vested	(5,186	)	$	4.95
Forfeited / Canceled	(672	)	$	6.38
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85
Granted	—		$	—
Vested	(3,034	)	$	5.34
Forfeited / Canceled	(2,592	)	$	4.31
Predecessor ending unvested restricted shares at October 1, 2016	—		$	—

The Predecessor Company issued share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the SandRidge Energy, Inc. 2009 Incentive Plan, (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 share-based compensation expense of $11.2 million, net of $1.7 million capitalized, for the Predecessor 2016 Period, and $21.7 million and $22.6 million, net of $5.9 million and $6.0 million capitalized for the years ended December 31, 2015 and 2014, respectively. 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.

In conjunction with the cancellation of the Predecessor Company’s common stock and termination of the 2009 Plan on the Emergence Date, the unrecognized compensation cost related to the Predecessor Company’s unvested restricted common stock awards of $5.9 million was expensed.

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Incentive and Deferred Compensation Plans

12 Months Ended

Dec. 31, 2016

Compensation Related Costs [Abstract]

Incentive and Deferred Compensation Plans

Incentive and Deferred Compensation Plans

Performance Incentive Plan. In January 2016, the Company implemented a performance incentive plan. The plan replaced, on a prospective basis, the Company’s previous annual incentive plan, including 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 payouts with a cash make up payment for above target performance based on the Company’s annual performance results to be made in the first quarter of 2017. 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, with approximately $15.8 million accrued at December 31, 2016 for payment in the first quarter of 2017.

Annual Incentive Plan. Prior to January 2016, for certain members of management, the annual incentive plan incorporated objective performance criteria, individual performance goals and competitive target award levels for the 2015 performance year with payout percentages ranging from 0% to 200% of specified target levels based on actual performance. As of December 31, 2015, the Company had accrued approximately $21.6 million for the annual incentive for all employees, including an accrual for an annual incentive for specified members of management based on actual performance compared to target levels specified in the annual incentive plan, which was paid in the first quarter of 2016.

Deferred Compensation Plans. 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 Internal Revenue Service (“IRS”) regulations. For the Successor 2016 Period, the Successor Company made matching cash contributions to the plan equal to 100% on the first 10% employee deferred wages for the period totaling $0.9 million. For the Predecessor 2016 Period, the Predecessor Company made matching cash contributions to the plan equal to 100% on the first 10% employee deferred wages for the period totaling$4.9 million. For the years endedDecember 31, 2015and2014, the Predecessor Company made matching contributions to the plan through cash purchases of Predecessor Company stock equal to 100% on the first 10% employee deferred wages. Retirement plan expense for the years ended December 31, 2015 and 2014 was approximately $7.9 million and $8.7 million, respectively. 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.

The Company maintains 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 Predecessor Company made insignificant matching contributions on non-qualified contributions for the Successor 2016 Period, the Predecessor 2016 Period and years ended December 31, 2015 and 2014. On December 31, 2016, the Successor Company began the process of terminating the non-qualified deferred compensation plan. No employee or employer contributions will be made to the plan after December 31, 2016 and in accordance with the plan termination procedures, the remaining assets held in the plan, of approximately $7.5 million as of December 31, 2016, will be fully distributed to participating employees throughout 2017 and the first quarter of 2018.

Any assets placed in trust by the Company to fund future obligations of the Company’s non-qualified deferred compensation plan are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their own deferred compensation in, and the Company’s contributions to, the plan.

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Income Taxes

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company’s income tax provision (benefit) consisted of the following components (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Current
Federal	$	—	$	—	$	—	$	(1,160	)
State	9		11		123		(1,133		)
	9		11		123		(2,293		)
Deferred
Federal	—		—		—		—
State	—		—		—		—
	—		—		—		—
Total provision (benefit)	9		11		123		(2,293		)
Less: income tax provision attributable to noncontrolling interest	—		—		90		283
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	9	$	11	$	33	$	(2,576	)

A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax provision (benefit) is as follows (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Computed at federal statutory rate	$	(116,891	)	$	504,283		$	(1,512,325	)	$	122,362
State taxes, net of federal benefit	(3,696		)	10,512			(19,988		)	4,145
Non-deductible expenses	144			462			816			1,895
Non-deductible debt costs	—			22,694			10,228			—
Stock-based compensation	306			5,884			6,700			1,467
Net effects of consolidating the non-controlling interests’ tax provisions	—			—			218,196			(34,614		)
Discharge of debt and other reorganization related items	—			359,278			—			—
Change in valuation allowance	120,144			(903,102		)	1,296,405			(96,769		)
Other	2			—			1			(1,062		)
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	9		$	11		$	33		$	(2,576	)

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. As of December 31, 2016, 2015 and 2014 the balance of the valuation allowance was $1.1 billion, $2.0 billion, and $649.6 million, respectively. 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. 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 net deferred tax asset at December 31, 2016. Thus, the Company’s effective tax rate and tax expense for the Successor 2016 Period and Predecessor 2016 Period continue to be low as a result of the Company not recognizing an income tax benefit associated with its net (loss) income from the same periods.

Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):

	Successor			Predecessor
	December 31, 2016			December 31, 2015
Deferred tax liabilities
Investments(1)	$	275,128		$	138,310
Derivative contracts	—			30,989
Long-term debt	—			10,017
Total deferred tax liabilities	275,128			179,316
Deferred tax assets
Property, plant and equipment	751,683			807,275
Derivative contracts	11,274			—
Allowance for doubtful accounts	1,487			18,702
Net operating loss carryforwards	527,079			1,190,799
Compensation and benefits	14,494			18,607
Alternative minimum tax credits and other carryforwards	43,770			44,302
Asset retirement obligations	40,399			38,314
CO2 under-delivery shortfall penalty	—			40,654
Other	4,663			4,305
Total deferred tax assets	1,394,849			2,162,958
Valuation allowance	(1,119,721		)	(1,983,642		)
Net deferred tax liability	$	—		$	—

____________________

(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.

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 discussed in Note 1, on the Emergence Date the Company’s existing convertible perpetual preferred stock and the Company’s common stock were canceled and New Common Stock was issued resulting in the Company experiencing an ownership change under IRC Section 382. Further, certain of the transactions that occurred upon the Company’s emergence from bankruptcy on October 4, 2016 materially impacted the Company’s tax attributes. Cancellation of indebtedness income resulting from these transactions reduced the Company’s tax attributes, including but not limited to federal net operating loss carryforwards, in the amount of $3.7 billion. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the October 4, 2016 ownership change and cancellation of indebtedness income on its tax attributes. Upon filing its 2016 U.S. Federal income tax return, the Company plans to elect an available alternative that does not subject existing tax attributes to an IRC Section 382 limitation. However, should an additional ownership change become likely to occur prior to filing its 2016 U.S. Federal income tax return, the Company will evaluate the remaining available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation which could result in some or all of the remaining net operating loss carryforwards expiring unused. The ownership change did not result in a current federal tax liability at December 31, 2016.

As of December 31, 2016, the Company had approximately $9.3 million of alternative minimum tax credits available that do not expire. In addition, the Company had approximately $1.3 billion of federal net operating loss carryovers after attribute reduction resulting from cancellation of indebtedness that expire during the years 2028 through 2036.

At December 31, 2016 and 2015, the Company had a liability of approximately $0.1 million for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015
Unrecognized tax benefit at January 1	$	81	$	81	$	77
Changes to unrecognized tax benefits related to a prior year	3		—		4
Unrecognized tax benefit at December 31	$	84	$	81	$	81

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, 2016, 2015 and 2014. The Company does not expect a significant change in its gross unrecognized tax benefits balance within the next 12 months.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2013 to present remain open for federal examination. Additionally, tax years 2005 through 2012 remain subject to examination for the purpose of determining the amount of federal net operating loss and other carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years.

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(Loss) Earnings per Share

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

(Loss) Earnings per Share

(Loss) Earnings per Share

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

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)
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(1)	—			—
Warrants(1)	—			—
New Convertible Notes(2)	—			—
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(3)	—			—
Diluted earnings per share	$	1,424,476		708,928	$	2.01
Year Ended December 31, 2015 (Predecessor)
Basic loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Effect of dilutive securities
Restricted stock and units(3)	—			—
Convertible preferred stock(4)	—			—
Convertible senior unsecured notes(5)	—			—
Diluted loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Year Ended December 31, 2014 (Predecessor)
Basic earnings per share	$	203,260		479,644	$	0.42
Effect of dilutive securities
Restricted stock	—			2,181
Convertible preferred stock(4)	6,500			17,918
Diluted earnings per share	$	209,760		499,743	$	0.42

____________________

(1) No incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive.

(2) Potential common shares related to the New 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.

(3) No incremental shares of potentially dilutive restricted stock awards or units were included for the Predecessor 2016 Period and the year ended December 31, 2015 as their effect was antidilutive under the treasury stock method.

(4) Potential common shares related to the Predecessor Company’s then-outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.2 million and 71.7 million shares for the years ended December 31, 2015 and 2014, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.

(5) Potential common shares related to the Predecessor Company’s then-outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 48.5 million shares for the year ended December 31, 2015 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

See Note 15 for discussion of the Predecessor Company’s convertible perpetual preferred stock. The remaining outstanding New Convertible Notes were converted into shares of New Common Stock as a result of the Company’s entry into the refinanced credit facility on February 10, 2017. For further discussion see Note 21.

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Related Party Transactions

12 Months Ended

Dec. 31, 2016

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

The Company entered into transactions in the ordinary course of business with certain related parties. These transactions primarily consisted of sales of oil and natural gas. See Note 10 for accounts payable attributable to related party transactions.

2014 Divestiture. See Note 5 for discussion of the sale of the Gulf Properties to Fieldwood and the Company’s guarantee on behalf of Fieldwood of certain associated plugging and abandonment obligations associated with the Gulf Properties. Fieldwood is a portfolio company of Riverstone Holdings LLC, affiliates of which owned a significant number of shares of the Predecessor Company’s common stock at the time the transaction occurred.

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Subsequent Events

12 Months Ended

Dec. 31, 2016

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Acquisition of Properties. On February 10, 2017, the Company acquired approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.8 million in cash. Also included in the acquisition were working interests in 4 wells previously drilled on the acreage.

Refinancing of New First Lien Exit Facility. On February 10, 2017, the New First Lien Exit Facility was refinanced into a new $600.0 million credit facility with a $425.0 million borrowing base. The amended credit facility agreement had the following impacts:

• increased the principal amount of commitments to $600.0 million from $425.0 million;

• extended the maturity date to March 31, 2020 from February 4, 2020;

• borrowing base determinations now include the Company’s proportionately consolidated share of proved reserves held by the Royalty Trusts;

• reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to 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;

• reduced the LIBOR floor from 1% to 0%;

• eliminated the minimum proved developing producing reserves asset coverage ratio;

• removed the requirement to maintain $50.0 million in a cash collateral account controlled by the administrative agent;

• eliminated the holiday from borrowing base determinations and the maximum consolidated total net leverage ratio and the minimum consolidated interest coverage ratio covenants; and

• eliminated certain negative covenants, such as the $20.0 million liquidity requirement and the limitation on capital expenditures.

Conversions of New Convertible Notes to New Common Stock. During the period from January 1, 2017 to February 9, 2017, holders of approximately $5.1 million in aggregate principal amount of the New Convertible Notes exercised conversion options applicable to those notes, resulting in the issuance of approximately 0.3 million shares of New Common Stock.

In conjunction with the refinancing of the New First Lien Exit Facility that took place on February 10, 2017, the remaining $263.7 million par value of the New Convertible Notes mandatorily converted into approximately 14.1 million shares of New Common Stock.

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

The supplemental information 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):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015			2014
Oil and natural gas properties
Proved	$	840,201		$	12,529,681		$	11,707,147
Unproved	74,937			363,149			290,596
Total oil and natural gas properties	915,138			12,892,830			11,997,743
Less accumulated depreciation, depletion and impairment	(353,030		)	(11,149,888		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	$	562,108		$	1,742,942		$	5,638,594

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):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Acquisitions of properties
Proved	$	5,142	$	3,897	$	35,376	$	73,370
Unproved	5,491		1,899		210,065		123,649
Exploration(1)	—		1,234		29,297		41,070
Development	27,429		149,924		571,562		1,288,395
Total cost incurred	$	38,062	$	156,954	$	846,300	$	1,526,484

____________________

(1) Includes seismic costs of $7.1 million and $10.8 million for the years ended December 31, 2015 and 2014, respectively.

Results of Operations for Oil and Natural Gas Producing Activities

The Company’s results of operations from oil and natural gas producing activities are shown in the following table (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Revenues	$	98,307		$	279,971		$	707,434		$	1,420,879
Expenses
Production costs	27,640			135,715			324,141			377,819
Depreciation and depletion	33,971			86,613			319,913			434,295
Accretion of asset retirement obligations	2,090			4,365			4,477			9,092
Impairment	319,087			657,392			4,473,787			164,779
Total expenses	382,788			884,085			5,122,318			985,985
(Loss) income before income taxes	(284,481		)	(604,114		)	(4,414,884		)	434,894
Income tax expense (benefit)(1)	8			(5		)	126			(2,852		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	(284,489	)	$	(604,109	)	$	(4,415,010	)	$	437,746

____________________

(1) Reflects the Company’s effective tax rate for each period.

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 such as the future prices of oil, natural gas and NGLs; 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 table below 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 with the SEC’s regulations. Estimates of the substantial majority of the Company’s proved reserves 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, Inc. (“CG&A”), Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2016, 2015 and 2014. CG&A, 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. CG&A and Ryder Scott prepared the estimates of proved reserves for a majority of the Company’s properties as of December 31, 2016. The remaining 6.0% of estimates of proved reserves was 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.

2016 Activity. During 2016, on a pro forma combined basis, 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.

2015 Activity. During 2015, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 9.7 MMBbls, 9.3 MMBbls, and 160.9 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Acquisition of the Rockies assets, located in Jackson County, Colorado, in December 2015 added 27.6 MMBoe of reserves. These positive revisions were offset by (i) negative pricing revisions of approximately 54 MMBbls for oil, 36 MMBbls for NGLs and 687 Bcf for natural gas, due primarily to significantly lower commodity prices in 2015, and (ii) negative revisions of approximately 16 MMBbls for oil, 1 MMBbls for NGLs and 74 Bcf for natural gas primarily from well performance in the Mid-Continent.

2014 Activity. During 2014, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 37.6 MMBbls, 27.5 MMBbls, and 467.2 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Revisions of previous estimates decreased oil reserves by 18.7 MMBbls, primarily comprised of (i) approximately 9 MMBbls from Permian Basin proved undeveloped reserves, largely due to removal of drilling locations not expected to be drilled within a five year period, (ii) approximately 8 MMBbls from well performance in the Mid-Continent and (iii) approximately 2 MMBbls from acreage losses or revisions to well interest ownerships. These negative revisions were offset by positive revisions to NGL and gas reserves of 11.1 MMBbls and 167.6 Bcf, respectively, primarily from well performance in the Mid-Continent area. Acquisitions of reserves added 3.5 MMBoe.

Sales of proved reserves during 2014 totaled 55.5 MMBoe from the sale of the Gulf Properties.

The summary below presents changes in the Company’s estimated reserves.

	Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2013 - Predecessor	142,641		59,052		1,390,429
Revisions of previous estimates	(18,687	)	11,103		167,589
Acquisitions of new reserves	1,009		441		12,527
Extensions and discoveries	37,603		27,500		467,185
Sales of reserves in place	(25,659	)	(2,516	)	(163,800	)
Production	(10,876	)	(3,794	)	(85,697	)
As of December 31, 2014(2) - Predecessor	126,031		91,786		1,788,233
Revisions of previous estimates	(70,708	)	(37,384	)	(759,106	)
Acquisitions of new reserves	22,447		2,460		15,952
Extensions and discoveries	9,741		9,257		160,865
Production	(9,600	)	(5,044	)	(92,104	)
As of December 31, 2015(2) - Predecessor	77,911		61,075		1,113,840
Adoption of ASU 2015-02	(6,971	)	(3,695	)	(50,508	)
Revisions of previous estimates	(39,973	)	(21,475	)	(415,568	)
Extensions and discoveries	987		472		7,955
Sales of reserves in place	(387	)	—		(145,267	)
Production	(4,315	)	(3,358	)	(44,124	)
As of October 1, 2016 - Predecessor	27,252		33,019		466,328
Revisions of previous estimates	23,978		1,139		915
Extensions and discoveries	2,868		448		10,309
Production	(1,214	)	(999	)	(12,770	)
As of December 31, 2016 - Successor	52,884		33,607		464,782
Proved developed reserves
As of December 31, 2013 - Predecessor	83,893		35,807		951,609
As of December 31, 2014 - Predecessor	79,022		56,823		1,203,447
As of December 31, 2015 - Predecessor	48,639		51,089		964,617
As of October 1, 2016 - Predecessor	24,541		30,238		428,050
As of December 31, 2016 - Successor	25,911		29,290		393,028
Proved undeveloped reserves
As of December 31, 2013 - Predecessor	58,748		23,245		438,820
As of December 31, 2014 - Predecessor	47,009		34,963		584,786
As of December 31, 2015 - Predecessor	29,272		9,986		149,223
As of October 1, 2016 - Predecessor	2,711		2,781		38,278
As of December 31, 2016 - Successor	26,973		4,317		71,754

____________________

(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	2014
Oil (MBbl)	7,004	11,027
NGL (MBbl)	3,694	4,761
Natural gas (MMcf)	50,508	70,833

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas (“ASC Topic 932”). 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 12-month average market prices at December 31, 2016, 2015 and 2014 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:

	Successor		Predecessor
	December 31,		December 31,
	2016		2015		2014
Oil (per barrel)	$	38.59	$	45.29	$	91.65
NGL (per barrel)	$	10.99	$	12.68	$	32.79
Natural gas (per Mcf)	$	1.56	$	1.87	$	3.61

• 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).

	Successor			Predecessor
	December 31,			December 31,
	2016			2015			2014
Future cash inflows from production	$	3,136,762		$	6,387,944		$	21,022,320
Future production costs	(1,454,798		)	(2,731,542		)	(6,499,366		)
Future development costs(1)	(665,516		)	(838,945		)	(1,810,201		)
Future income tax expenses	(142		)	(901		)	(3,223,740		)
Undiscounted future net cash flows	1,016,306			2,816,556			9,489,013
10% annual discount	(577,942		)	(1,501,994		)	(5,401,261		)
Standardized measure of discounted future net cash flows(2)	$	438,364		$	1,314,562		$	4,087,752

____________________

(1) Includes abandonment costs.

(2) Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015 and 2014 respectively.

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):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning present value	$	392,604		$	1,314,562		$	4,087,752		$	4,017,611
Changes during the year
Adoption of ASU 2015-02	—			(224,965		)	—			—
Revenues less production and other costs	(70,668		)	(144,256		)	(383,293		)	(1,043,060		)
Net changes in prices, production and other costs	35,684			(394,173		)	(3,813,465		)	331,694
Development costs incurred	7,941			69,080			217,596			364,262
Net changes in future development costs	(291,232		)	436,041			273,437			(341,183		)
Extensions and discoveries	14,986			12,449			230,055			1,785,963
Revisions of previous quantity estimates	308,374			(728,254		)	(1,354,778		)	(77,688		)
Accretion of discount	9,375			91,337			512,483			477,458
Net change in income taxes	—			402			1,426,333			(256,371		)
Purchases of reserves in-place	—			—			18,429			50,958
Sales of reserves in-place	—			(13,314		)	—			(1,058,330		)
Timing differences and other(1)	31,300			(26,305		)	100,013			(163,562		)
Net change for the year	45,760			(921,958		)	(2,773,190		)	70,141
Ending present value(2)	$	438,364		$	392,604		$	1,314,562		$	4,087,752

____________________

(1) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2) Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015, and 2014 respectively.

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Quarterly Financial Results (Unaudited)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Results (Unaudited)

Quarterly Financial Results (Unaudited)

The Company’s operating results for each quarter of 2016 and 2015 are summarized below (in thousands, except per share data).

	Predecessor											Successor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter		Fourth Quarter
2016
Total revenues	$	90,332		$	99,421		$	104,056		$	—	$	98,456
Loss from operations(1)(2)	$	(273,555	)	$	(275,310	)	$	(357,338	)	$	—	$	(336,345	)
Net (loss) income(1)(2)(3)	$	(313,226	)	$	(515,911	)	$	(404,337	)	$	2,674,271	(333,982		)
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(1)(2)(3)	$	(324,107	)	$	(521,351	)	$	(404,337	)	$	2,674,271	$	(333,982	)
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
Basic	$	(0.47	)	$	(0.73	)	$	(0.56	)	$	3.72	$	(17.61	)
Diluted	$	(0.47	)	$	(0.73	)	$	(0.56	)	$	3.72	$	(17.61	)

	Predecessor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2015
Total revenues	$	215,308		$	229,607		$	180,152		$	143,642
Loss from operations(4)(5)	$	(1,088,456	)	$	(1,535,083	)	$	(1,059,733	)	$	(959,406	)
Net loss(4)(5)	$	(1,151,874	)	$	(1,588,731	)	$	(796,485	)	$	(783,961	)
Loss applicable to SandRidge Energy, Inc. common stockholders(4)(5)	$	(1,045,834	)	$	(1,375,556	)	$	(649,526	)	$	(664,579	)
Loss applicable per share to SandRidge Energy, Inc. common stockholders(6)
Basic	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
Diluted	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)

____________________

(1) Includes impairment of $110.1 million, $253.6 million, $354.5 million and $319.1 million for the first, second, and third quarters and Successor 2016 Period, respectively. See Note 9 for further discussion of impairment.

(2) Includes loss on settlement of contract of $89.1 million and gain on extinguishment of $41.3 million for the first quarter.

(3) Includes (loss) gain on reorganization items related to the Company’s restructuring under Chapter 11 filings of $(200.9) million, $(42.8) million, and $2.7 billion for the second and third quarters and Predecessor fourth quarter, respectively. See Note 2 for further discussion of reorganization items.

(4) Includes impairment of $1.1 billion, $1.5 billion, $1.1 billion and $886.8 million for the first, second, third and fourth quarters, respectively. See Note 9 for further discussion of impairment.

(5) Includes (gain) loss on derivative contracts of $(49.8) million, $33.0 million, $(42.2) million and $(14.0) million for the first, second, third and fourth quarters, respectively.

(6) Loss applicable per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of loss applicable per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business

Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent and Rockies regions of the United States. The Company’s Rockies properties were acquired during the fourth quarter of 2015. Additionally, the Company owned interests in the Gulf of Mexico and Gulf Coast until February 2014, as discussed in Note 5.

Principles of Consolidation

Principles of Consolidation. The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, realization of assets and satisfaction of liabilities in the normal course of business. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. During the years ended December 31, 2015, and 2014, the Company fully consolidated the activities of each the SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Mississippian Trust II (the “Mississippian Trust II”) and SandRidge Permian Trust (the “Permian Trust”) (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) as variable interest entities (“VIEs”) for which the Company was the primary beneficiary. Activities of the Royalty Trusts attributable to third party ownership were presented as noncontrolling interest and included as a component of equity in the condensed consolidated balance sheet as of December 31, 2015. As discussed further below, during the year ended December 31, 2016, the Company proportionately consolidated the activities of the Royalty Trusts. All significant intercompany accounts and transactions have been eliminated in consolidation.

Reclassifications

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

Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and natural gas liquids (“NGL”) reserves; impairment tests of long-lived assets; 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

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

Restricted Cash. The Companymaintains restricted escrow funds as required by certain contractual arrangements in accordance with the Plan.

Accounts Receivable, Net

Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the exploration, production and treating services for 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 collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. As part of fresh start accounting, the allowance for doubtful accounts was reset to zero on the Emergence Date. Refer to Note 7 for further information on the Company’s accounts receivable and allowance for doubtful accounts.

Fair Value of Financial Instruments

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, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 6 for further discussion of the Company’s fair value measurements.

Fair Value of Non-financial Assets and Liabilities

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 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. Fair value measurements for the electrical asset were based on replacement cost. Inputs used in the cost approach are based on the cost to a market participant buyer to acquire or construct a substitute asset of comparable utility, adjusted for inutility. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 6.

Derivative Financial Instruments

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.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. 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 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 12 for further discussion of the Company’s derivatives.

Oil and Natural Gas Operations

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 Company capitalized internal costs during the Successor 2016 Period of $4.0 million and the Predecessor Company capitalized internal costs of $22.7 million, $45.1 million and $55.4 million to the full cost pool during the Predecessor 2016 Period and the years ended December 31, 2015 and 2014, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. 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.

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 an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. 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

Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, electrical infrastructure, transportation equipment and other property and equipment are carried at cost. 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 10 to 39 years for buildings and 2 to 30 years for equipment. When property and equipment components are disposed, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations. As part of fresh start accounting, property, plant and equipment were adjusted to their estimated fair value and depreciable lives were revised as of October 1, 2016, as described in Note 2.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. Impairment is measured as the excess of the carrying amount of the impaired asset or asset group over its fair value. See Note 9 for further discussion of impairments.

Capitalized Interest

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.

Debt Issuance Costs

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 scheduled maturity period of the related debt. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.

Investments

Investments. Investments in marketable equity securities relate primarily to the Company’s non-qualified deferred compensation plan, and have been designated as available for sale and measured at fair value using quoted prices readily available in the market pursuant to the 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 sheets.

Asset Retirement Obligations

Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, 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 well is sold, at which time 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 rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 13 for further discussion of the Company’s asset retirement obligations. As part of fresh start accounting, the ARO liabilities were adjusted to their estimated fair value as described in Note 2.

Revenue Recognition

For the years ended December 31, 2015 and 2014, the Company recognized revenues and expenses generated from daywork and footage drilling contracts as the services were performed since the Company did not bear the risk of completion of the well. The Company received lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another were recognized at the time mobilization services were performed. Revenues and expenses related to drilling and services are included in other revenue and expense in the accompanying consolidated statements of operations for the years ended December 31, 2015 and 2014.

In general, natural gas purchased and sold by the midstream business was priced at a published daily or monthly index price. Sales to wholesale customers typically incorporated a premium for managing their transmission and balancing requirements. Midstream services revenues were recognized upon delivery of natural gas to customers and/or when services were rendered, pricing was determined and collectability was reasonably assured. Revenues from third-party midstream services were presented on a gross basis, since the Company acted as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold. Revenues and expenses related to midstream and marketing are included in other revenue and expense in the accompanying consolidated statements of operations for the years ended December 31, 2015 and 2014.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Additionally, the Successor Company has made an accounting policy election to deduct transportation costs from oil, natural gas and NGL revenues. This resulted in presenting $7.4 million of transportation costs as a reduction from revenues in the Successor 2016 Period versus the presentation of $26.2 million, $45.3 million and $35.6 million of these costs as production expenses in the Predecessor 2016 Period, and the years ended December 31, 2015 and 2014, respectively. and Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

Natural Gas Balancing

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $1.7 million and $1.5 million at December 31, 2016 and 2015, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

Share-based Compensation

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

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 are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.

Earnings per Share

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.

Under the if-converted method, the Successor Company assumes the conversion of the New Convertible Notes to common stock and determines if it is more dilutive than including the expense associated with the New Convertible Notes in the computation of income available to common stockholders. Under the if-converted method, the Predecessor Company assumed the conversion of the preferred stock or Convertible Senior Unsecured Notes to common stock 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 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 19 for the Company’s earnings per share calculation.

Commitments and Contingencies

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. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 14 for discussion of the Company’s commitments and contingencies.

Concentration of Risk

Concentration of Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s commodity derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its commodity derivative counterparties and considers its counterparties’ 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 its exposure to any individual counterparty.

A default by the Company under its New First Lien Exit Facility constitutes a default under its commodity derivative contracts with counterparties that are lenders under the New First Lien Exit 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 First Lien Exit Facility can be offset against amounts owed, if any, to such counterparty under the Company’s First Lien Exit 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 consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major 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 the Company’s ability to sell the oil, natural gas and NGLs it produces.

The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):

	Sales		% of Revenue
Period from October 2, 2016 through December 31, 2016 - Successor
Targa Pipeline Mid-Continent West OK LLC	$	35,845	36.4	%
Plains Marketing, L.P.	$	32,022	32.5	%
Period from January 1, 2016 through October 1, 2016 - Predecessor
Plains Marketing, L.P.	$	110,370	37.6	%
Targa Pipeline Mid-Continent West OK LLC	$	108,238	36.8	%
December 31, 2015 - Predecessor
Plains Marketing, L.P.	$	318,018	41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649	30.1	%
December 31, 2014 - Predecessor
Plains Marketing, L.P.	$	597,117	38.3	%
Targa Pipeline Mid-Continent West OK LLC	$	333,027	21.4	%

Recent Accounting Pronouncements

Recent Accounting Pronouncements. The Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) 2015-02, “Amendments to the Consolidation Analysis,” which simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a VIE. The requirements of the guidance were effective for annual reporting periods beginning January 1, 2016 for the Company, including interim periods within that reporting period, with early adoption permitted. The Company adopted this guidance on January 1, 2016, which resulted in the determination that the Royalty Trusts no longer qualify as VIEs. As a result, the Successor and Predecessor Companies proportionately consolidated the activities of the Royalty Trusts in 2016. Under the proportionate consolidation method, the Company accounts for only its share of each Royalty Trust’s asset, liabilities, revenues and expenses within the appropriate classifications in the accompanying consolidated financial statements. The Company adopted the provisions of ASU 2015-02 on a modified retrospective approach by recording a cumulative-effect adjustment as of January 1, 2016 that resulted in decreases of approximately $243.4 million to total assets and approximately $510.2 million to noncontrolling interest and increases of approximately $9.7 million to accounts payable and approximately $257.1 million to retained earnings. These adjustments had no impact on prior period balances.

The FASB issued ASU 2015-03, "Interest-Imputation of Interest (Topic 835): Simplifying the Presentation of Debt Issuance Costs," which requires debt issuance costs related to a recognized debt liability to be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability rather than as an asset. The guidance was adopted on January 1, 2016, and resulted in a decrease of approximately $69.1 million to other assets and current maturities of long-term debt in the accompanying consolidated balance sheet for the year ended December 31, 2015, with no impact to the accompanying consolidated statements of operations. See Note 11 for treatment and classification of unamortized debt issuance costs subsequent to filing the Chapter 11 petitions. In August 2015, the FASB issued ASU 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements,” which excludes line-of-credit debt issuance costs from the scope of ASU 2015-03. The guidance was adopted on January 1, 2016 in conjunction with the adoption of ASU 2015-03. The Company made an accounting policy election to present line-of-credit arrangement debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement. The adoption of this ASU resulted in no impact to the consolidated financial statements.

The FASB issued ASU 2014-15, “Presentation of Financial Statements - Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if conditions or events raise substantial doubt about the entity’s ability to continue as a going concern. The Company adopted the provisions of this ASU for the year ended December 31, 2016 on a prospective basis. The adoption of this ASU had no impact to the Company’s disclosures included in this report.

The FASB issued ASU 2016-06, “Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments” which eliminates diversity in practice in assessing embedded contingent call (put) options in debt instruments. The ASU requires adoption by application of a modified retrospective approach to existing and future debt instruments. The ASU is effective for the Company beginning January 1, 2017, with early adoption permitted. The Company early adopted the provisions of this ASU on the Emergence Date. The adoption of this ASU resulted in no impact to the consolidated financial statements and related disclosures.

The FASB issued ASU 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Share-Based Payment Accounting” which was part of the FASB simplification initiative and involves several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance requires adoption by various application methods, effective for the Company beginning January 1, 2017. The Company early adopted all provisions of this ASU on the Emergence Date. Upon adoption, the Company made an accounting policy election to account for forfeitures as they occur. The adoption of this ASU resulted in no impact to the consolidated financial statements and related disclosures.

The FASB issued ASU 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash” to require inclusion of amounts generally described as restricted cash or restricted cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. This ASU is effective for the Company beginning January 1, 2018. The Company early adopted the provisions of this ASU on December 31, 2016, using a retrospective transition method for each period presented. As a result of the adoption, the Company included $52.8 million of restricted cash in the beginning of period and end of period total amounts shown on the Successor statement of cash flows for October 2, 2016 and December 31, 2016, respectively. There was no impact to the Predecessor statement of cash flows.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which provides guidance concerning the recognition and measurement of revenue 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 defers the effective date of ASU 2014-09 to January 1, 2018 for the Company, with early adoption permitted in 2017. The ASU must be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes 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 does not plan to early adopt and is currently evaluating the effect that the updated standard will have on its consolidated financial statements and related disclosures.

The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for the Company on January 1, 2019. Early adoption is permitted. The Company does not plan to early adopt and is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

The FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” with the objective of reducing the existing diversity in practice of classification on certain cash receipts and payments in the statement of cash flows. The guidance requires adoption by application of a retrospective method to each period presented. The amendments are effective for the Company on January 1, 2018, with early adoption permitted. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements.

The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory” which removes 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 are effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU should be applied 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 does not plan to early adopt and is currently evaluating the effect that the guidance will have on its consolidated financial statements.

The FASB Issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides more consistency in applying the guidance, reduces the costs of application, and makes the definition of a business more operable. The ASU is effective for the Company on January 1, 2018 and amendments should be applied prospectively on and after January 1, 2018. Due to the prospective nature of the ASU, the Company cannot evaluate the impact to its consolidated financial statements until after adoption, and no disclosures are required upon transition.

Fair Value Transfers

Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred.

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Fresh Start Accounting (Tables)

12 Months Ended

Dec. 31, 2016

Reorganizations [Abstract]

Reconciliation of Enterprise Value to Fair Value

The following table reconciles the enterprise value to the estimated fair value of the Successor Company's common stock as of the Emergence Date (in thousands, except per share amounts):

Enterprise value	$	1,089,808
Plus: Cash and cash equivalents	563,372
Less: Fair value of New Building Note	(36,610		)
Less: Asset retirement obligation	(92,412		)
Less: Fair value of New First Lien Exit Facility	(414,954		)
Less: Fair value of New Convertible Notes	(445,660		)
Less: Fair value of warrants, including warrants held in reserve for settlement of general unsecured claims	(95,794		)
Fair value of Successor common stock issued upon emergence	$	567,750
Shares issued upon emergence on October 4, 2016, including shares held in reserve for settlement of general unsecured claims	19,371
Per share value	$	29.31

Reconciliation Of Enterprise Value To Estimated Reorganization Value

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 equivalents	563,372
Plus: other working capital liabilities	131,766
Plus: other long-term liabilities	8,549
Reorganization value of Successor assets	$	1,793,495

Schedule of Fresh-Start Adjustments

The following table reflects the reorganization and application of Accounting Standards Codification (“ASC”) 852 “Reorganizations” on the consolidated balance sheet as of October 1, 2016 (in thousands):

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
ASSETS
Current assets
Cash and cash equivalents	$	652,680		$	(142,148	)	(1)	$	—			$	510,532
Restricted cash - collateral	—			50,000			(2)	—				50,000
Restricted cash - other	—			2,840			(2)	—				2,840
Accounts receivable, net	61,446			12,356			(3)	—				73,802
Derivative contracts	10,192			—				(669		)	(12)	9,523
Prepaid expenses	12,514			(8,218		)	(4)	—				4,296
Other current assets	1,003			—				3,217			(13)	4,220
Total current assets	737,835			(85,170		)		2,548				655,213
Oil and natural gas properties, using full cost method of accounting
Proved	12,093,492			—				(11,344,684		)	(14)	748,808
Unproved	322,580			—				(205,578		)	(14)	117,002
Less: accumulated depreciation, depletion and impairment	(11,637,538		)	—				11,637,538			(14)	—
	778,534			—				87,276				865,810
Other property, plant and equipment, net	357,528			(41		)		(93,782		)	(15)	263,705
Derivative contracts	70			—				(70		)	(12)	—
Other assets	12,537			(3,770		)	(5)	—				8,767
Total assets	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	140,448		$	(14,820	)	(6)	$	—			$	125,628
Derivative contracts	2,982			—				1,666			(12)	4,648
Asset retirement obligations	8,573			—				57,105			(16)	65,678
Total current liabilities	152,003			(14,820		)		58,771				195,954
Long-term debt	—			731,735			(7)	1,610			(17)	733,345
Derivative contracts	935			—				304			(12)	1,239
Asset retirement obligations	62,896			—				(36,161		)	(16)	26,735
Other long-term obligations	3			8,798			(8)	(3		)		8,798
Liabilities subject to compromise	4,346,188			(4,346,188		)	(9)	—				—
Total liabilities	4,562,025			(3,620,475		)		24,521				966,071
Equity
SandRidge Energy, Inc. stockholders’ equity (deficit)
Predecessor preferred stock	6			—				(6		)	(18)	—
Predecessor common stock	718			—				(718		)	(18)	—
Predecessor additional paid-in capital	5,315,655			—				(5,315,655		)	(18)	—
Predecessor additional paid-in capital—stockholder receivable	(1,250		)	1,250			(10)	—				—
Predecessor treasury stock, at cost	(5,218		)	—				5,218			(18)	—
Successor common stock	—			19			(11)	—				19
Successor warrants	—			88,382			(11)	—				88,382
Successor additional paid-in capital	—			739,023			(11)	—				739,023
Accumulated deficit	(7,985,411		)	2,702,820			(9)	5,282,591			(19)	—
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	(2,675,500		)	3,531,494				(28,570		)		827,424
Noncontrolling interest	(21		)	—				21			(20)	—
Total stockholders’ (deficit) equity	(2,675,521		)	3,531,494				(28,549		)		827,424
Total liabilities and stockholders’ equity (deficit)	$	1,886,504		$	(88,981	)		$	(4,028	)		$	1,793,495

Reorganization Adjustments

1. Reflects the net cash payments made upon emergence (in thousands):

Sources:
Proceeds from New Building Note	$	26,847
Total sources	$	26,847
Uses and transfers:
Cash transferred to restricted accounts (collateral and general unsecured claims)	$	52,840
Payments and funding of escrow account related to professional fees	43,770
Payment on Senior Credit facility (principal and interest)	35,238
Repayment of Senior Secured Notes and Unsecured Notes	33,874
Payment of certain contract cures and other	3,273
Total uses and transfers	168,995
Net uses and transfers	$	(142,148	)

2. Funding of $50.0 million Cash Collateral account and the funding of $2.8 million to be held in reserve by the Company for distribution to satisfy allowed general unsecured claims as specified under the Plan.

3. Accrual for future reimbursement of the unused portion of the professional fees escrow account and other receivables.

4. Write-off of prepaid expenses primarily related to $7.5 million of prepaid premium for the Predecessor Company’s directors and officers insurance policy.

5. Application of a $3.8 million deposit held by a utility service toward the settlement of the utility service’s claims under the Plan.

6. Includes a $43.8 million decrease in accrued liabilities as a result of funding an escrow account established for the payment of professional fees, partially offset by the reinstatement of certain liabilities subject to compromise as accounts payable and accrued expenses.

7. Principal balances of $35.0 million of the New Building Note, $281.8 million of the New Convertible Notes, and the $415.0 million drawn on the New First Lien Exit Facility.

8. Reclassification of non-qualified deferred compensation plan and gas balancing liabilities from liabilities subject to compromise to other long term obligations, as these liabilities became obligations of the Successor.

9. Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):

Current maturities of long-term debt and accrued interest	$	4,179,483
Accounts payable and accrued expenses	157,422
Other long-term liabilities	9,283
Liabilities subject to compromise of the Predecessor	4,346,188
Cash payments at emergence	(72,385		)
Cash proceeds from building mortgage	26,847
Write-off of prepaid accounts upon emergence	(8,218		)
Accrual for future reimbursement from professional fees escrow account and other receivables	12,356
Total consideration given pursuant to the Plan:
Fair value of equity issued	(827,424		)
Principal value of long-term debt issued and reinstated at emergence	(731,735		)
Reinstatement of liabilities subject to compromise as accounts payable and accrued expenses	(37,789		)
Release of stockholder receivable	(1,250		)
Application of deposit held by utility services	(3,770		)
Gain on settlement of liabilities subject to compromise	$	2,702,820

10. Release of a receivable from the Predecessor’s former director and officer as outlined in the Plan.

11. The following table reconciles reorganization adjustments made to Successor common stock, warrants and additional paid in capital (in thousands):

Par value of 18.9 million shares of New Common Stock issued to former holders of the Senior Secured Notes and Unsecured Notes (valued at $29.31 per share)	$	19
Fair value of warrants issued to holders of the Unsecured Notes(1)	88,382
Additional paid in capital - New Common Stock	575,144
Additional paid in capital - premium on New Convertible Notes(2)	163,879
Total Successor Company equity issued on Emergence Date	$	827,424

____________________

(1) The fair value of the warrants was estimated using a Black-Scholes-Merton model with the following assumptions: implied stock price of the Successor Company; exercise price per share of $41.34 and $42.03 for Warrant classes A and B, respectively; expected volatility of 59.26%; risk free interest rate, continuously compounded, of 1.36%; and holding period of six years.

(2) The fair value of the New Convertible Notes was estimated using a Monte Carlo simulation with the following assumptions; the implied Successor Company stock price; expected volatility of 56.06%; risk free interest rate, continuously compounded, of 1.08%; recovery rate of 15.00%; hazard rate of 12.41%; drop on default of 100.00%; and termination period after four years. The premium is the difference between the fair value of the New Convertible Notes of $445.7 million and the principal value of the New Convertible Notes of $281.8 million.

Fresh Start Adjustments

12. Adjustments and reclassifications of derivative contracts based on their Emergence Date fair values, which were determined using the fair value methodology for commodity derivative contracts discussed in Note 6.

13. Fair value adjustment to other current assets to record assets held for sale at their anticipated sales prices.

14. Fair value adjustments to oil and natural gas properties, including asset retirement obligation, associated inventory, unproved acreage and seismic. See above for detailed discussion of fair value methodology.

15. Adjustments to other property, plant and equipment to record the assets at their respective fair values on the Emergence Date. A combination of the cost approach and income approach were utilized to determine the fair values of the Company’s headquarters and other properties located in downtown Oklahoma City, Oklahoma, and the cost approach was utilized to determine the fair value of all other property, plant and equipment.

16. Fair value adjustments to the Company’s asset retirement obligations as a result of applying fresh start accounting. Upon implementation of fresh start accounting, the Company revalued these obligations based upon updates to wells’ productive lives and application of the Successor Company’s credit adjusted risk fee rate.

17. Fair value adjustment to record premium on the New Building Note.

18. Cancellation of Predecessor Company’s common stock, preferred stock, treasury stock and paid-in capital.

19. Adjustment to reset retained deficit to zero.

20. Elimination of the Predecessor non-controlling interest.

Reorganization Items

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 settlements	84,228
Loss on mortgage	(8,153		)
Gain on preferred stock dividends	37,893
Fresh start valuation adjustments	(28,549		)
Fair value of equity issued	(827,424		)
Principal value of New Convertible Notes issued	(281,780		)
Gain on reorganization items, net	$	2,430,599

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Summary of Significant Accounting Policies Summary (Tables)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Schedules of Concentration of Risk

The Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):

	Sales		% of Revenue
Period from October 2, 2016 through December 31, 2016 - Successor
Targa Pipeline Mid-Continent West OK LLC	$	35,845	36.4	%
Plains Marketing, L.P.	$	32,022	32.5	%
Period from January 1, 2016 through October 1, 2016 - Predecessor
Plains Marketing, L.P.	$	110,370	37.6	%
Targa Pipeline Mid-Continent West OK LLC	$	108,238	36.8	%
December 31, 2015 - Predecessor
Plains Marketing, L.P.	$	318,018	41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649	30.1	%
December 31, 2014 - Predecessor
Plains Marketing, L.P.	$	597,117	38.3	%
Targa Pipeline Mid-Continent West OK LLC	$	333,027	21.4	%

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2016

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items	$	—		$	(55,606	)	$	—		$	—
Cash paid for interest, net of amounts capitalized	$	(1,183	)	$	(104,609	)	$	(296,386	)	$	(235,793	)
Cash (paid) received for income taxes	$	—		$	(28	)	$	(88	)	$	1,928
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	$	10,630		$	25,045		$	177,586		$	(55,557	)
Equity issued for debt	$	(13,001	)	$	(4,409	)	$	(63,299	)	$	—
Preferred stock dividends paid in common stock	$	—		$	—		$	(16,188	)	$	—
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$	—		$	—		$	(50,310	)	$	—

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

Significant Unobservable Inputs - Liabilities

The significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion features atDecember 31, 2015are included in the table below.

Unobservable Input	Range					Weighted Average		Fair Value
								(In thousands)
Debt conversion feature hazard rate	114.0	%	–	135.2	%	119.2	%	$	29,355

Assets and Liabilities Measured at Fair Value on Recurring 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, 2016 - Successor

	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Investments	$	7,541	$	—	$	—	$	—	$	7,541
	$	7,541	$	—	$	—	$	—	$	7,541
Liabilities
Commodity derivative contracts	$	—	$	29,714	$	—	$	—	$	29,714
	$	—	$	29,714	$	—	$	—	$	29,714

December 31, 2015 - Predecessor

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	85,524	$	—	$	(1,175	)	$	84,349
Investments	10,106		—		—		—			10,106
	$	10,106	$	85,524	$	—	$	(1,175	)	$	94,455
Liabilities
Commodity derivative contracts	$	—	$	—	$	1,748	$	(1,175	)	$	573
Debt holder conversion feature	—		—		29,355		—			29,355
Mandatory prepayment feature - PGC Senior Secured Notes	—		2,941		—		—			2,941
	$	—	$	2,941	$	31,103	$	(1,175	)	$	32,869

____________________

(1)Represents the impact of netting assets and liabilities with counterparties where the right of offset exists.

Fair Value, Reconciliation of Level 3 Fair Value Measurements - Liabilities

The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for debt holder conversion features (in thousands):

	Predecessor
	Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015
Beginning balance	$	29,355		$	—
Issuances	—			31,200
(Loss) gain on derivative holder conversion feature	(880		)	10,198
Conversions	(21,194		)	(12,043		)
Write off of derivative holder conversion feature to reorganization items	(7,281		)	—
Ending level 3 debt holder conversion feature balance	$	—		$	29,355

Estimated Fair Value and Carrying Value of the Company's Notes

The estimated fair values and carrying values of the Company’s notes are as follows (in thousands):

	Successor				Predecessor
	December 31, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
New Convertible Notes	$	334,800	$	268,780	$	—	$	—
New Building Note	$	40,608	$	36,528	$	—	$	—
8.75% Senior Secured Notes due 2020	$	—	$	—	$	403,098	$	1,265,814
Senior Unsecured Notes
8.75% Senior Notes due 2020	$	—	$	—	$	39,740	$	389,232
7.5% Senior Notes due 2021	$	—	$	—	$	79,812	$	751,087
8.125% Senior Notes due 2022	$	—	$	—	$	57,749	$	518,693
7.5% Senior Notes due 2023	$	—	$	—	$	58,799	534,869
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022	$	—	$	—	$	44,199	$	78,290
7.5% Convertible Senior Notes due 2023	$	—	$	—	$	15,125	$	24,393

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Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2016

Receivables [Abstract]

Summary of Accounts Receivable

A summary of accounts receivable is as follows (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
Oil, natural gas and NGL sales	$	42,631		$	61,140
Joint interest billing	17,338			60,403
Oil and natural gas services	736			2,417
Other	14,272			8,274
Total accounts receivable	74,977			132,234
Less: allowance for doubtful accounts	(880		)	(4,847		)
Total accounts receivable, net	$	74,097		$	127,387

Balance and Activity in Allowance for Doubtful Accounts

The following table presents the balance and activity in the allowance for doubtful accounts for the Successor 2016 Period, the Predecessor 2016 Period and years ended December 31, 2015 and 2014 (in thousands):

	Successor					Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning balance	$	—	$	4,847		$	7,083		$	11,061
Additions charged to costs and expenses(1)	880		16,695			1,320			818
Deductions(2)	—		(751		)	(3,556		)	(4,796		)
Impact of fresh start accounting	—		(20,791		)	—			—
Ending balance	$	880	$	—		$	4,847		$	7,083

____________________

(1) The Predecessor 2016 Period includes an addition for a joint interest account receivable after a determination that future collection was doubtful.

(2) Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2015 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement and deductions in 2014 are related to the sale of the Gulf Properties.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, plant and equipment consists of the following (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015
Oil and natural gas properties
Proved(1)	$	840,201		$	12,529,681
Unproved	74,937			363,149
Total oil and natural gas properties	915,138			12,892,830
Less accumulated depreciation, depletion and impairment	(353,030		)	(11,149,888		)
Net oil and natural gas properties capitalized costs	562,108			1,742,942
Land	5,100			14,260
Non-oil and natural gas equipment(2)	166,010			373,687
Buildings and structures(3)	88,603			227,673
Total	259,713			615,620
Less accumulated depreciation and amortization	(3,889		)	(123,860		)
Other property, plant and equipment, net	255,824			491,760
Total property, plant and equipment, net	$	817,932		$	2,234,702

____________________

(1) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $48.9 million at December 31, 2015.

(2) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $4.3 million at December 31, 2015.

(3) No interest was capitalized for the Successor 2016 Period. Includes cumulative capitalized interest of approximately $20.4 million at December 31, 2015.

Capitalized Costs of Unproved Properties Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2016 (in thousands):

			Year Cost Incurred
	Total		2016		2015		2014		2013 and Prior
Property acquisition	$	71,171	$	7,390	$	18,959	$	34,770	$	10,052
Exploration(1)	20,459		2,123		10,578		4,678		3,080
Total costs incurred	$	91,630	$	9,513	$	29,537	$	39,448	$	13,132

____________________

(1) Includes $16.7 million of pipe inventory costs incurred ($2.1 million in 2016, $9.6 million in 2015 and $5.0 million in 2014 and prior years).

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Impairment (Tables)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment [Abstract]

Schedule of Impairment by Asset Class

Impairment consists of the following (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Full cost pool ceiling limitation(1)(2)(3)	$	319,087	$	657,392	$	4,473,787	$	164,779
Drilling assets(4)	—		3,511		37,646		27,428
Electrical transmission assets(5)	—		55,600		—		—
Midstream assets(6)	—		1,691		7,148		561
Other(7)	—		—		16,108		—
	$	319,087	$	718,194	$	4,534,689	$	192,768

____________________

(1) Impairment recorded in the Successor 2016 Period resulted from the application of fresh start accounting. 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 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 impairments recorded in 2015 and the first two quarters of 2016 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015 and the first half of 2016. The impairment recorded in the third quarter of 2016 resulted primarily from downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes.

(3) Impairment in 2014 resulted from the divestiture of the Gulf Properties.

(4) Impairment recorded in the Predecessor 2016 Period and the year ended December 31, 2015, resulted from discontinued drilling operations in its Permian region which resulted in an impairment on certain drilling assets after determining their future use was limited. During 2014, the Company recorded a $24.3 million impairment on its drilling and oilfield services assets in the Permian region as a result of fulfilling its drilling obligation with the Permian Trust in 2014 and the downward trend in oil prices that began in the second half of 2014.

(5) Impairment in the Predecessor 2016 Period resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage.

(6) Impairment in the Predecessor 2016 Period and the years ended December 31, 2015 and 2014 resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a carbon dioxide (“CO₂”) compressor station after determining that their future use was limited.

(7) Impairment recorded on other assets in 2015, includes a $15.4 million impairment on property located in downtown Oklahoma City, Oklahoma to adjust the carrying value of the property to the agreed upon sales price for which it was later sold in 2016.

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Accounts Payable and Accrued Expenses (Tables)

12 Months Ended

Dec. 31, 2016

Payables and Accruals [Abstract]

Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):

	Successor		Predecessor
	December 31,		December 31,
	2016		2015
Accounts payable and other accrued expenses	$	65,408	$	231,697
Accrued interest	648		73,320
Production payable	16,011		55,260
Payroll and benefits	33,606		42,728
Convertible perpetual preferred stock dividends	—		21,572
Drilling advances	844		2,295
Related party	—		1,545
Total accounts payable and accrued expenses	$	116,517	$	428,417

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Long-Term Debt

Long-term debt consists of the following (in thousands):

	Successor		Predecessor
	December 31,		December 31,
	2016		2015
New First Lien Exit Facility	$	—	$	—
New Convertible Notes	268,780		—
New Building Note	36,528		—
Senior credit facility	—		—
8.75% Senior Secured Notes due 2020	—		1,265,814
Senior Unsecured Notes
8.75% Senior Notes due 2020	—		389,232
7.5% Senior Notes due 2021	—		751,087
8.125% Senior Notes due 2022	—		518,693
7.5% Senior Notes due 2023	—		534,869
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022	—		78,290
7.5% Convertible Senior Notes due 2023	—		24,393
Total debt	305,308		3,562,378
Less: current maturities of long-term debt	—		—
Long-term debt	$	305,308	$	3,562,378

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Offsetting Assets and Liabilities

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 New First Lien Exit Facility and senior credit facility (in thousands):

December 31, 2016 - Successor

	Gross Amounts		Gross Amounts Offset		Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	—	$	—	$	—	$	—		$	—
Derivative contracts - noncurrent	—		—		—		—			—
Total	$	—	$	—	$	—	$	—		$	—
Liabilities
Derivative contracts - current	$	27,538	$	—	$	27,538	$	(27,538	)	$	—
Derivative contracts - noncurrent	2,176		—		2,176		(2,176		)	—
Total	$	29,714	$	—	$	29,714	$	(29,714	)	$	—

December 31, 2015 - Predecessor

	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Liabilities
Derivative contracts - current	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—

Open Oil and Natural Gas Commodity Derivative Contracts

At December 31, 2016, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2017 - December 2017	3,285	$	52.24
January 2018 - December 2018	1,825	$	55.34

Natural Gas Price Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2017 - December 2017	32,850	$	3.20
January 2018 - December 2018	3,650	$	3.12

Fair Value of Derivative Contracts

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):

		Successor			Predecessor
		December 31,			December 31,
Type of Contract	Balance Sheet Classification	2016			2015
Derivative assets
Oil price swaps	Derivative contracts - current	$	—		$	68,224
Oil collars—three way	Derivative contracts - current	—			17,300
Derivative liabilities
Oil price swaps	Derivative contracts - current	(13,395		)	—
Natural gas price swaps	Derivative contracts - current	(14,143		)	—
Natural gas basis swaps	Derivative contracts - current	—			(1,748		)
Debt holder conversion feature	Current maturities of long-term debt	—			(29,355		)
Mandatory prepayment feature - PGC Senior Secured Notes	Current maturities of long-term debt	—			(2,941		)
Oil price swaps	Derivative contracts - noncurrent	(2,105		)	—
Natural gas price swaps	Derivative contracts - noncurrent	(71		)	—
Total net derivative contracts		$	(29,714	)	$	51,480

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations

The following table presents the balance and activity of the asset retirement obligations (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning balance	$	92,413		$	103,578		$	54,402		$	424,117
Liability incurred upon acquiring and drilling wells	121			505			1,662			4,968
Revisions in estimated cash flows(1)	12,397			—			44,060			(5,848		)
Liability settled or disposed in current period(2)	(540		)	(36,979		)	(1,023		)	(377,927		)
Accretion	2,090			4,365			4,477			9,092
Impact of fresh start accounting	—			20,944			—			—
Ending balance	106,481			92,413			103,578			54,402
Less: current portion	66,154			65,678			8,399			—
Asset retirement obligations, net of current	$	40,327		$	26,735		$	95,179		$	54,402

____________________

(1) Revisions for the Successor 2016 Period and the year ended December 31, 2015 relate primarily to changes in estimated well lives.

(2) Liability settled or disposed for the Predecessor 2016 Period includes $34.1 million associated with the WTO Properties sold in January 2016. Liability settled or disposed for the year ended December 31, 2014, includes $366.0 million associated with the Gulf Properties sold in February 2014. For further discussion of the sale of properties see Note 5.

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Equity (Tables)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Preferred Stock Terms

The following table summarizes information about each series of the Predecessor Company’s convertible perpetual preferred stock outstanding at December 31, 2015:

	Convertible Perpetual Preferred Stock
	8.5%		7.0%
Liquidation preference per share	$	100.00	$	100.00
Annual dividend per share	$	8.50	$	7.00
Conversion rate per share to common stock	12.4805		12.8791

Preferred Stock Dividends

Preferred stock dividend payments and accruals for the Company’s 8.5%, 7.0% and 6.0% convertible perpetual preferred stock are as follows (in thousands):

	Predecessor
	Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
8.5% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	11,262	$	22,525
Dividends satisfied in shares of common stock(1)	$	—	$	11,262	$	—
Accrued dividends at period end	$	—	$	8,447	$	8,447
Dividends in arrears	$	11,262	$	—	$	—
7.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	—	$	21,000
Dividends satisfied in shares of common stock(2)	$	—	$	10,500	$	—
Accrued dividends at period end	$	—	$	13,125	$	2,625
Dividends in arrears	$	21,000	$	10,500	$	—
6.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	—	$	12,000
Accrued dividends at period end	$	—	$	—	$	—

____________________

(1) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 18.6 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, ($3.58 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

(2) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 5.7 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, ($2.23 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying consolidated statement of operations.

Treasury Stock Activity

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.

	Predecessor
	Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Number of shares withheld for taxes	1,122		1,872		1,034
Value of shares withheld for taxes	$	44	$	2,428	$	6,373

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Unvested Restricted Stock Awards

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, 2013	7,643		$	6.92
Granted	6,367		$	6.17
Vested	(3,432	)	$	7.04
Forfeited / Canceled	(2,022	)	$	6.60
Unvested restricted shares outstanding at December 31, 2014	8,556		$	6.39
Granted	2,928		$	0.88
Vested	(5,186	)	$	4.95
Forfeited / Canceled	(672	)	$	6.38
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85
Granted	—		$	—
Vested	(3,034	)	$	5.34
Forfeited / Canceled	(2,592	)	$	4.31
Predecessor ending unvested restricted shares at October 1, 2016	—		$	—

The 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	—		$	—
Granted	1,448		$	24.32
Vested	(14	)	$	24.32
Forfeited / Canceled	(27	)	$	24.32
Unvested restricted shares outstanding at December 31, 2016	1,407		$	24.32

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

(Benefit) Provision for Income Taxes

The Company’s income tax provision (benefit) consisted of the following components (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Current
Federal	$	—	$	—	$	—	$	(1,160	)
State	9		11		123		(1,133		)
	9		11		123		(2,293		)
Deferred
Federal	—		—		—		—
State	—		—		—		—
	—		—		—		—
Total provision (benefit)	9		11		123		(2,293		)
Less: income tax provision attributable to noncontrolling interest	—		—		90		283
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	9	$	11	$	33	$	(2,576	)

Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate

A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax provision (benefit) is as follows (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Computed at federal statutory rate	$	(116,891	)	$	504,283		$	(1,512,325	)	$	122,362
State taxes, net of federal benefit	(3,696		)	10,512			(19,988		)	4,145
Non-deductible expenses	144			462			816			1,895
Non-deductible debt costs	—			22,694			10,228			—
Stock-based compensation	306			5,884			6,700			1,467
Net effects of consolidating the non-controlling interests’ tax provisions	—			—			218,196			(34,614		)
Discharge of debt and other reorganization related items	—			359,278			—			—
Change in valuation allowance	120,144			(903,102		)	1,296,405			(96,769		)
Other	2			—			1			(1,062		)
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	9		$	11		$	33		$	(2,576	)

Deferred Tax Assets and Liabilities

Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):

	Successor			Predecessor
	December 31, 2016			December 31, 2015
Deferred tax liabilities
Investments(1)	$	275,128		$	138,310
Derivative contracts	—			30,989
Long-term debt	—			10,017
Total deferred tax liabilities	275,128			179,316
Deferred tax assets
Property, plant and equipment	751,683			807,275
Derivative contracts	11,274			—
Allowance for doubtful accounts	1,487			18,702
Net operating loss carryforwards	527,079			1,190,799
Compensation and benefits	14,494			18,607
Alternative minimum tax credits and other carryforwards	43,770			44,302
Asset retirement obligations	40,399			38,314
CO2 under-delivery shortfall penalty	—			40,654
Other	4,663			4,305
Total deferred tax assets	1,394,849			2,162,958
Valuation allowance	(1,119,721		)	(1,983,642		)
Net deferred tax liability	$	—		$	—

____________________

(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts.

Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015
Unrecognized tax benefit at January 1	$	81	$	81	$	77
Changes to unrecognized tax benefits related to a prior year	3		—		4
Unrecognized tax benefit at December 31	$	84	$	81	$	81

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(Loss) Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share

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)
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(1)	—			—
Warrants(1)	—			—
New Convertible Notes(2)	—			—
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(3)	—			—
Diluted earnings per share	$	1,424,476		708,928	$	2.01
Year Ended December 31, 2015 (Predecessor)
Basic loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Effect of dilutive securities
Restricted stock and units(3)	—			—
Convertible preferred stock(4)	—			—
Convertible senior unsecured notes(5)	—			—
Diluted loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Year Ended December 31, 2014 (Predecessor)
Basic earnings per share	$	203,260		479,644	$	0.42
Effect of dilutive securities
Restricted stock	—			2,181
Convertible preferred stock(4)	6,500			17,918
Diluted earnings per share	$	209,760		499,743	$	0.42

____________________

(1) No incremental shares of potentially dilutive restricted stock awards or warrants were included for the Successor 2016 Period as their effect was antidilutive.

(2) Potential common shares related to the New 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.

(3) No incremental shares of potentially dilutive restricted stock awards or units were included for the Predecessor 2016 Period and the year ended December 31, 2015 as their effect was antidilutive under the treasury stock method.

(4) Potential common shares related to the Predecessor Company’s then-outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.2 million and 71.7 million shares for the years ended December 31, 2015 and 2014, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.

(5) Potential common shares related to the Predecessor Company’s then-outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 48.5 million shares for the year ended December 31, 2015 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

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Supplemental Information on Oil and Natural Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2016

Extractive Industries [Abstract]

Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):

	Successor			Predecessor
	December 31,			December 31,
	2016			2015			2014
Oil and natural gas properties
Proved	$	840,201		$	12,529,681		$	11,707,147
Unproved	74,937			363,149			290,596
Total oil and natural gas properties	915,138			12,892,830			11,997,743
Less accumulated depreciation, depletion and impairment	(353,030		)	(11,149,888		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	$	562,108		$	1,742,942		$	5,638,594

Cost 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):

	Successor		Predecessor
	Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015		Year Ended December 31, 2014
Acquisitions of properties
Proved	$	5,142	$	3,897	$	35,376	$	73,370
Unproved	5,491		1,899		210,065		123,649
Exploration(1)	—		1,234		29,297		41,070
Development	27,429		149,924		571,562		1,288,395
Total cost incurred	$	38,062	$	156,954	$	846,300	$	1,526,484

____________________

(1) Includes seismic costs of $7.1 million and $10.8 million for the years ended December 31, 2015 and 2014, respectively.

Results of Operations for Oil, Natural Gas and NGL Producing Activities

The Company’s results of operations from oil and natural gas producing activities are shown in the following table (in thousands):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Revenues	$	98,307		$	279,971		$	707,434		$	1,420,879
Expenses
Production costs	27,640			135,715			324,141			377,819
Depreciation and depletion	33,971			86,613			319,913			434,295
Accretion of asset retirement obligations	2,090			4,365			4,477			9,092
Impairment	319,087			657,392			4,473,787			164,779
Total expenses	382,788			884,085			5,122,318			985,985
(Loss) income before income taxes	(284,481		)	(604,114		)	(4,414,884		)	434,894
Income tax expense (benefit)(1)	8			(5		)	126			(2,852		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	(284,489	)	$	(604,109	)	$	(4,415,010	)	$	437,746

____________________

(1) Reflects the Company’s effective tax rate for each period.

Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves

The summary below presents changes in the Company’s estimated reserves.

	Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2013 - Predecessor	142,641		59,052		1,390,429
Revisions of previous estimates	(18,687	)	11,103		167,589
Acquisitions of new reserves	1,009		441		12,527
Extensions and discoveries	37,603		27,500		467,185
Sales of reserves in place	(25,659	)	(2,516	)	(163,800	)
Production	(10,876	)	(3,794	)	(85,697	)
As of December 31, 2014(2) - Predecessor	126,031		91,786		1,788,233
Revisions of previous estimates	(70,708	)	(37,384	)	(759,106	)
Acquisitions of new reserves	22,447		2,460		15,952
Extensions and discoveries	9,741		9,257		160,865
Production	(9,600	)	(5,044	)	(92,104	)
As of December 31, 2015(2) - Predecessor	77,911		61,075		1,113,840
Adoption of ASU 2015-02	(6,971	)	(3,695	)	(50,508	)
Revisions of previous estimates	(39,973	)	(21,475	)	(415,568	)
Extensions and discoveries	987		472		7,955
Sales of reserves in place	(387	)	—		(145,267	)
Production	(4,315	)	(3,358	)	(44,124	)
As of October 1, 2016 - Predecessor	27,252		33,019		466,328
Revisions of previous estimates	23,978		1,139		915
Extensions and discoveries	2,868		448		10,309
Production	(1,214	)	(999	)	(12,770	)
As of December 31, 2016 - Successor	52,884		33,607		464,782
Proved developed reserves
As of December 31, 2013 - Predecessor	83,893		35,807		951,609
As of December 31, 2014 - Predecessor	79,022		56,823		1,203,447
As of December 31, 2015 - Predecessor	48,639		51,089		964,617
As of October 1, 2016 - Predecessor	24,541		30,238		428,050
As of December 31, 2016 - Successor	25,911		29,290		393,028
Proved undeveloped reserves
As of December 31, 2013 - Predecessor	58,748		23,245		438,820
As of December 31, 2014 - Predecessor	47,009		34,963		584,786
As of December 31, 2015 - Predecessor	29,272		9,986		149,223
As of October 1, 2016 - Predecessor	2,711		2,781		38,278
As of December 31, 2016 - Successor	26,973		4,317		71,754

____________________

(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	2014
Oil (MBbl)	7,004	11,027
NGL (MBbl)	3,694	4,761
Natural gas (MMcf)	50,508	70,833

Calculation of Weighted Average Per Unit Prices

The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:

	Successor		Predecessor
	December 31,		December 31,
	2016		2015		2014
Oil (per barrel)	$	38.59	$	45.29	$	91.65
NGL (per barrel)	$	10.99	$	12.68	$	32.79
Natural gas (per Mcf)	$	1.56	$	1.87	$	3.61

Standardized Measure of Discounted Future 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).

	Successor			Predecessor
	December 31,			December 31,
	2016			2015			2014
Future cash inflows from production	$	3,136,762		$	6,387,944		$	21,022,320
Future production costs	(1,454,798		)	(2,731,542		)	(6,499,366		)
Future development costs(1)	(665,516		)	(838,945		)	(1,810,201		)
Future income tax expenses	(142		)	(901		)	(3,223,740		)
Undiscounted future net cash flows	1,016,306			2,816,556			9,489,013
10% annual discount	(577,942		)	(1,501,994		)	(5,401,261		)
Standardized measure of discounted future net cash flows(2)	$	438,364		$	1,314,562		$	4,087,752

____________________

(1) Includes abandonment costs.

(2) Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015 and 2014 respectively.

Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

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):

	Successor			Predecessor
	Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015			Year Ended December 31, 2014
Beginning present value	$	392,604		$	1,314,562		$	4,087,752		$	4,017,611
Changes during the year
Adoption of ASU 2015-02	—			(224,965		)	—			—
Revenues less production and other costs	(70,668		)	(144,256		)	(383,293		)	(1,043,060		)
Net changes in prices, production and other costs	35,684			(394,173		)	(3,813,465		)	331,694
Development costs incurred	7,941			69,080			217,596			364,262
Net changes in future development costs	(291,232		)	436,041			273,437			(341,183		)
Extensions and discoveries	14,986			12,449			230,055			1,785,963
Revisions of previous quantity estimates	308,374			(728,254		)	(1,354,778		)	(77,688		)
Accretion of discount	9,375			91,337			512,483			477,458
Net change in income taxes	—			402			1,426,333			(256,371		)
Purchases of reserves in-place	—			—			18,429			50,958
Sales of reserves in-place	—			(13,314		)	—			(1,058,330		)
Timing differences and other(1)	31,300			(26,305		)	100,013			(163,562		)
Net change for the year	45,760			(921,958		)	(2,773,190		)	70,141
Ending present value(2)	$	438,364		$	392,604		$	1,314,562		$	4,087,752

____________________

(1) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2) Includes approximately $224.6 million and $643.3 million attributable to noncontrolling interests at December 31, 2015, and 2014 respectively.

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Quarterly Financial Results (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Results (Unaudited)

The Company’s operating results for each quarter of 2016 and 2015 are summarized below (in thousands, except per share data).

	Predecessor											Successor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter		Fourth Quarter
2016
Total revenues	$	90,332		$	99,421		$	104,056		$	—	$	98,456
Loss from operations(1)(2)	$	(273,555	)	$	(275,310	)	$	(357,338	)	$	—	$	(336,345	)
Net (loss) income(1)(2)(3)	$	(313,226	)	$	(515,911	)	$	(404,337	)	$	2,674,271	(333,982		)
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(1)(2)(3)	$	(324,107	)	$	(521,351	)	$	(404,337	)	$	2,674,271	$	(333,982	)
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
Basic	$	(0.47	)	$	(0.73	)	$	(0.56	)	$	3.72	$	(17.61	)
Diluted	$	(0.47	)	$	(0.73	)	$	(0.56	)	$	3.72	$	(17.61	)

	Predecessor
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2015
Total revenues	$	215,308		$	229,607		$	180,152		$	143,642
Loss from operations(4)(5)	$	(1,088,456	)	$	(1,535,083	)	$	(1,059,733	)	$	(959,406	)
Net loss(4)(5)	$	(1,151,874	)	$	(1,588,731	)	$	(796,485	)	$	(783,961	)
Loss applicable to SandRidge Energy, Inc. common stockholders(4)(5)	$	(1,045,834	)	$	(1,375,556	)	$	(649,526	)	$	(664,579	)
Loss applicable per share to SandRidge Energy, Inc. common stockholders(6)
Basic	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
Diluted	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)

____________________

(1) Includes impairment of $110.1 million, $253.6 million, $354.5 million and $319.1 million for the first, second, and third quarters and Successor 2016 Period, respectively. See Note 9 for further discussion of impairment.

(2) Includes loss on settlement of contract of $89.1 million and gain on extinguishment of $41.3 million for the first quarter.

(3) Includes (loss) gain on reorganization items related to the Company’s restructuring under Chapter 11 filings of $(200.9) million, $(42.8) million, and $2.7 billion for the second and third quarters and Predecessor fourth quarter, respectively. See Note 2 for further discussion of reorganization items.

(4) Includes impairment of $1.1 billion, $1.5 billion, $1.1 billion and $886.8 million for the first, second, third and fourth quarters, respectively. See Note 9 for further discussion of impairment.

(5) Includes (gain) loss on derivative contracts of $(49.8) million, $33.0 million, $(42.2) million and $(14.0) million for the first, second, third and fourth quarters, respectively.

(6) Loss applicable per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of loss applicable per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

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Voluntary Reorganization under Chapter 11 Proceedings - Narrative (Details) $ / shares in Units, shares in Millions		9 Months Ended	12 Months Ended
	Oct. 01, 2016 USD ($) shares director $ / shares	Oct. 01, 2016 USD ($) director $ / shares shares	Dec. 31, 2015 USD ($)	Oct. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)
New First Lien Exit Facility | Revolving Credit Facility
Restructuring Cost and Reserve [Line Items]
Maximum borrowing capacity	$ 425,000,000	$ 425,000,000
7.0% Convertible perpetual preferred stock
Restructuring Cost and Reserve [Line Items]
Preferred stock, dividend rate, percentage			7.00%
8.5% Convertible perpetual preferred stock
Restructuring Cost and Reserve [Line Items]
Preferred stock, dividend rate, percentage			8.50%
Predecessor
Restructuring Cost and Reserve [Line Items]
Face value of long-term debt			$ 3,562,378,000
Predecessor | Convertible Debt
Restructuring Cost and Reserve [Line Items]
Notes exchanged/converted		$ 232,100,000	255,300,000
Predecessor | New First Lien Exit Facility | Revolving Credit Facility
Restructuring Cost and Reserve [Line Items]
Face value of long-term debt			$ 0
Predecessor | 8.75% Senior Secured Notes due 2020 | Secured Notes
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate	8.75%	8.75%	8.75%		8.75%
Face amount of debt instrument				$ 78,000,000	$ 1,250,000,000.0
Face value of long-term debt			$ 1,265,814,000
Predecessor | New Building Note | Secured Notes
Restructuring Cost and Reserve [Line Items]
Face value of long-term debt			$ 0
Predecessor | 8.75% Senior Notes due 2020 | Senior Notes
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate	8.75%	8.75%	8.75%
Face value of long-term debt			$ 389,232,000
Predecessor | 7.5% Senior Notes due 2021 | Senior Notes
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%
Face value of long-term debt			$ 751,087,000
Predecessor | 8.125% Senior Notes due 2022 | Senior Notes
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate	8.125%	8.125%	8.125%
Face value of long-term debt			$ 518,693,000
Predecessor | 8.125% Convertible Senior Notes due 2022
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate			8.125%
Predecessor | 8.125% Convertible Senior Notes due 2022 | Convertible Debt
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate	8.125%	8.125%	8.125%
Notes exchanged/converted		$ 200,500,000	$ 186,600,000
Face value of long-term debt			$ 78,290,000
Predecessor | 7.5% Convertible Senior Notes due 2023
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate			7.50%
Predecessor | 7.5% Convertible Senior Notes due 2023 | Convertible Debt
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%
Notes exchanged/converted		$ 31,600,000	$ 68,700,000
Face value of long-term debt			$ 24,393,000
Predecessor | 7.5% Senior Notes due 2023 | Senior Notes
Restructuring Cost and Reserve [Line Items]
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%
Face value of long-term debt			$ 534,869,000
Predecessor | 7.0% Convertible perpetual preferred stock
Restructuring Cost and Reserve [Line Items]
Preferred stock, dividend rate, percentage	7.00%		7.00%
Predecessor | 8.5% Convertible perpetual preferred stock
Restructuring Cost and Reserve [Line Items]
Preferred stock, dividend rate, percentage	8.50%		8.50%
Predecessor | Plan of Reorganization
Restructuring Cost and Reserve [Line Items]
Number of employee directors | director	5	5
Number of non-employee directors | director	4	4
Predecessor | Plan of Reorganization | Holders of Senior Credit Facility | Revolving Credit Facility
Restructuring Cost and Reserve [Line Items]
Cash payments for prepetition obligations	$ 35,000,000	$ 35,000,000
Predecessor | Plan of Reorganization | Holders of Senior Secured Notes | Convertible Debt
Restructuring Cost and Reserve [Line Items]
Face amount of debt instrument	$ 281,800,000	$ 281,800,000
Annual interest rate	0.00%	0.00%
Number of shares issuable under convertible securities | shares	15.0
Predecessor | Plan of Reorganization | Holders of Unsecured Claims
Restructuring Cost and Reserve [Line Items]
Cash payments for prepetition obligations	$ 36,700,000	$ 36,700,000
Predecessor | Plan of Reorganization | Series A Warrants | Holders of Unsecured Claims
Restructuring Cost and Reserve [Line Items]
Number of shares to be issued | shares	4.9	4.9
Shares issued | shares	4.5
Exercise price of warrants (in usd per share) | $ / shares	$ 41.34	$ 41.34
Predecessor | Plan of Reorganization | Series B Warrants | Holders of Unsecured Claims
Restructuring Cost and Reserve [Line Items]
Number of shares to be issued | shares	2.1	2.1
Shares issued | shares	1.9
Exercise price of warrants (in usd per share) | $ / shares	$ 42.03	$ 42.03
Predecessor | Plan of Reorganization | New First Lien Exit Facility
Restructuring Cost and Reserve [Line Items]
Cash collateral	$ 50,000,000	$ 50,000,000
Cash collateral to be released upon delivery of acceptable business plan	12,500,000	12,500,000
Cash collateral to be released upon achievement for two consecutive quarters of certain milestones	12,500,000	12,500,000
Cash collateral to be released upon meeting minimum ratio of proved producing reserves to aggregate principal loan commitments	$ 25,000,000	$ 25,000,000
Minimum ratio of proved producing reserves to aggregate principal loan commitments	2.00	2.00
Predecessor | Plan of Reorganization | New First Lien Exit Facility | Revolving Credit Facility
Restructuring Cost and Reserve [Line Items]
Maximum borrowing capacity	$ 425,000,000	$ 425,000,000
Predecessor | Plan of Reorganization | 8.75% Senior Secured Notes due 2020 | Holders of Senior Secured Notes | Secured Notes
Restructuring Cost and Reserve [Line Items]
Notes exchanged/converted	78,000,000
Predecessor | Plan of Reorganization | New Building Note | Secured Notes
Restructuring Cost and Reserve [Line Items]
Face amount of debt instrument	35,000,000	$ 35,000,000
Proceeds from issuance of debt	$ 26,800,000
Predecessor | Plan of Reorganization | New Common Stock
Restructuring Cost and Reserve [Line Items]
Common stock, shares authorized | shares	18.9	18.9
Predecessor | Plan of Reorganization | New Common Stock | Holders of Senior Secured Notes
Restructuring Cost and Reserve [Line Items]
Shares issued | shares	13.7
Predecessor | Plan of Reorganization | New Common Stock | Holders of Unsecured Claims
Restructuring Cost and Reserve [Line Items]
Number of shares to be issued | shares	5.7	5.7
Shares issued | shares	5.2
Predecessor | Plan of Reorganization | 7.0% Convertible perpetual preferred stock
Restructuring Cost and Reserve [Line Items]
Preferred stock, dividend rate, percentage	7.00%
Predecessor | Plan of Reorganization | 8.5% Convertible perpetual preferred stock
Restructuring Cost and Reserve [Line Items]
Preferred stock, dividend rate, percentage	8.50%

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Fresh Start Accounting - Narrative (Details) $ in Thousands	Oct. 01, 2016 USD ($)
Predecessor | Minimum
Schedule of Reorganization Items [Line Items]
Estimated enterprise value	$ 1,040,000
Predecessor | Maximum
Schedule of Reorganization Items [Line Items]
Estimated enterprise value	1,320,000
Successor
Schedule of Reorganization Items [Line Items]
Enterprise value	$ 1,089,808
Discount Factor	10.00%
Fair value of proved properties	$ 632,800
Fair value of undeveloped leasehold acreage	$ 113,900

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Fresh Start Accounting - Reconciliation of Enterprise Value to Fair Value (Details) - Successor - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	Dec. 31, 2016	Oct. 01, 2016
Reconciliation of Enterprise Value to Fair Value
Enterprise value		$ 1,089,808
Plus: Cash and cash equivalents	$ (121,231)	(563,372)
Less: Fair value of New Building Note		(36,610)
Less: Asset retirement obligation		(92,412)
Less: Fair value of New First Lien Exit Facility		(414,954)
Less: Fair value of New Convertible Notes		(445,660)
Less: Fair value of warrants, including warrants held in reserve for settlement of general unsecured claims		(95,794)
Fair value of Successor common stock issued upon emergence		$ 567,750
Shares issued upon emergence on October 4, 2016, including shares held in reserve for settlement of general unsecured claims	19,635	19,371
Per share value (in dollars per share)		$ 29.31

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Fresh Start Accounting - Reconciliation Of Enterprise Value To Estimated Reorganization Value (Details) - Successor - USD ($) $ in Thousands	Oct. 02, 2016	Oct. 01, 2016
Reconciliation Of Enterprise Value To Estimated Reorganization Value [Line Items]
Enterprise value		$ 1,089,808
Plus: cash and cash equivalents	$ (510,532)	563,372
Plus: other working capital liabilities	195,954	131,766
Plus: other long-term liabilities	$ 8,798	8,549
Reorganization value of Successor assets		$ 1,793,495

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Fresh Start Accounting - Application of Fresh Start Accounting to Balance Sheet (Details) - USD ($) $ in Thousands	Oct. 02, 2016	Oct. 01, 2016
Reorganization Adjustments
Current assets
Cash and cash equivalents		$ (142,148)
Restricted cash - collateral		50,000
Restricted cash - other		2,840
Accounts receivable, net		12,356
Derivative contracts		0
Prepaid expenses		(8,218)
Other current assets		0
Total current assets		(85,170)
Oil and natural gas properties, using full cost method of accounting
Proved		0
Unproved		0
Less: accumulated depreciation, depletion and impairment		0
Net oil and natural gas properties capitalized costs		0
Noncurrent Assets
Other property, plant and equipment, net		(41)
Derivative contracts		0
Other assets		(3,770)
Total assets		(88,981)
Current liabilities
Accounts payable and accrued expenses		(14,820)
Derivative contracts		0
Asset retirement obligations		0
Total current liabilities		(14,820)
Noncurrent Liabilities
Long-term debt		731,735
Derivative contracts		0
Asset retirement obligations		0
Other long-term obligations		8,798
Liabilities subject to compromise		(4,346,188)
Total liabilities		(3,620,475)
Equity
Preferred stock		0
Common stock		19
Additional paid-in capital		739,023
Additional paid-in capital - stockholder receivable		1,250
Treasury stock, at cost		0
Warrants		88,382
Accumulated deficit		2,702,820
Total SandRidge Energy, Inc. stockholders’ (deficit) equity		3,531,494
Noncontrolling interest		0
Total stockholders’ (deficit) equity		3,531,494
Total liabilities and stockholders’ equity (deficit)		(88,981)
Fresh Start Adjustments
Current assets
Cash and cash equivalents		0
Restricted cash - collateral		0
Restricted cash - other		0
Accounts receivable, net		0
Derivative contracts		(669)
Prepaid expenses		0
Other current assets		3,217
Total current assets		2,548
Oil and natural gas properties, using full cost method of accounting
Proved		(11,344,684)
Unproved		(205,578)
Less: accumulated depreciation, depletion and impairment		11,637,538
Net oil and natural gas properties capitalized costs		87,276
Noncurrent Assets
Other property, plant and equipment, net		(93,782)
Derivative contracts		(70)
Other assets		0
Total assets		(4,028)
Current liabilities
Accounts payable and accrued expenses		0
Derivative contracts		1,666
Asset retirement obligations		57,105
Total current liabilities		58,771
Noncurrent Liabilities
Long-term debt		1,610
Derivative contracts		304
Asset retirement obligations		(36,161)
Other long-term obligations		(3)
Liabilities subject to compromise		0
Total liabilities		24,521
Equity
Preferred stock		(6)
Common stock		(718)
Additional paid-in capital		(5,315,655)
Additional paid-in capital - stockholder receivable		0
Treasury stock, at cost		5,218
Warrants		0
Accumulated deficit		5,282,591
Total SandRidge Energy, Inc. stockholders’ (deficit) equity		(28,570)
Noncontrolling interest		21
Total stockholders’ (deficit) equity		(28,549)
Total liabilities and stockholders’ equity (deficit)		(4,028)
Predecessor
Current assets
Cash and cash equivalents		652,680
Restricted cash - collateral		0
Restricted cash - other		0
Accounts receivable, net		61,446
Derivative contracts		10,192
Prepaid expenses		12,514
Other current assets		1,003
Total current assets		737,835
Oil and natural gas properties, using full cost method of accounting
Proved		12,093,492
Unproved		322,580
Less: accumulated depreciation, depletion and impairment		(11,637,538)
Net oil and natural gas properties capitalized costs		778,534
Noncurrent Assets
Other property, plant and equipment, net		357,528
Derivative contracts		70
Other assets		12,537
Total assets		1,886,504
Current liabilities
Accounts payable and accrued expenses		140,448
Derivative contracts		2,982
Asset retirement obligations		8,573
Total current liabilities		152,003
Noncurrent Liabilities
Long-term debt		0
Derivative contracts		935
Asset retirement obligations		62,896
Other long-term obligations		3
Liabilities subject to compromise		4,346,188
Total liabilities		4,562,025
Equity
Preferred stock		6
Common stock		718
Additional paid-in capital		5,315,655
Additional paid-in capital—stockholder receivable		(1,250)
Treasury stock, at cost		(5,218)
Warrants		0
Accumulated deficit		(7,985,411)
Total SandRidge Energy, Inc. stockholders’ (deficit) equity		(2,675,500)
Noncontrolling interest		(21)
Total stockholders’ (deficit) equity		(2,675,521)
Total liabilities and stockholders’ equity (deficit)		1,886,504
Predecessor | Reorganization Adjustments
Current assets
Prepaid expenses		8,218
Noncurrent Assets
Other assets		(3,770)
Noncurrent Liabilities
Liabilities subject to compromise		4,346,188
Noncurrent Liabilities
Long-term debt		731,735
Equity
Additional paid-in capital - stockholder receivable		1,250
Equity
Total SandRidge Energy, Inc. stockholders’ (deficit) equity		827,424
Successor
Current assets
Cash and cash equivalents	$ 510,532	(563,372)
Restricted cash - collateral	50,000
Restricted cash - other	2,840
Accounts receivable, net	73,802
Derivative contracts	9,523
Prepaid expenses	4,296
Other current assets	4,220
Total current assets	655,213
Oil and natural gas properties, using full cost method of accounting
Proved	748,808
Unproved	117,002
Less: accumulated depreciation, depletion and impairment	0
Net oil and natural gas properties capitalized costs	865,810
Noncurrent Assets
Other property, plant and equipment, net	263,705
Derivative contracts	0
Other assets	8,767
Total assets	1,793,495
Current liabilities
Accounts payable and accrued expenses	125,628
Derivative contracts	4,648
Asset retirement obligations	65,678
Total current liabilities	195,954	131,766
Noncurrent Liabilities
Long-term debt	733,345
Derivative contracts	1,239
Asset retirement obligations	26,735
Other long-term obligations	8,798	$ 8,549
Liabilities subject to compromise	0
Total liabilities	966,071
Equity
Preferred stock	0
Common stock	19
Additional paid-in capital	739,023
Additional paid-in capital - stockholder receivable	0
Treasury stock, at cost	0
Warrants	88,382
Accumulated deficit	0
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	827,424
Noncontrolling interest	0
Total stockholders’ (deficit) equity	827,424
Total liabilities and stockholders’ equity (deficit)	$ 1,793,495

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Fresh Start Accounting - Cash Payments Made Upon Emergence (Details) - Reorganization Adjustments $ in Thousands	Oct. 01, 2016 USD ($)
Fresh-Start Adjustment [Line Items]
Proceeds from New Building Note	$ 26,847
Cash transferred to restricted accounts (collateral and general unsecured claims)	52,840
Payments and funding of escrow account related to professional fees	43,770
Payment on Senior Credit facility (principal and interest)	35,238
Repayment of Senior Secured Notes and Unsecured Notes	33,874
Payment of certain contract cures and other	3,273
Total uses and transfers	168,995
Net uses and transfers	$ (142,148)

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Fresh Start Accounting - Reorganization Adjustments (Details) $ in Thousands	Oct. 01, 2016 USD ($)
Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Increase in restricted cash - collateral	$ 50,000
Increase in restricted cash - other	2,840
Write-off of prepaid expenses	8,218
Write-off of prepaid deposit	3,770
Decrease in accrued liabilities	43,800
Increase in long-term debt	(731,735)
Reorganization Adjustments | Restricted by Debt Agreement
Fresh-Start Adjustment [Line Items]
Increase in restricted cash - collateral	50,000
Reorganization Adjustments | New Building Note | Secured Debt
Fresh-Start Adjustment [Line Items]
Increase in long-term debt	(35,000)
Reorganization Adjustments | New Convertible Notes | Convertible Debt
Fresh-Start Adjustment [Line Items]
Increase in long-term debt	(281,800)
Reorganization Adjustments | New First Lien Exit Facility | Revolving Credit Facility
Fresh-Start Adjustment [Line Items]
Increase in long-term debt	(415,000)
Write off of director and officer insurance premium
Fresh-Start Adjustment [Line Items]
Write-off of prepaid expenses	7,500
Predecessor | Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Write-off of prepaid expenses	(8,218)
Write-off of prepaid deposit	3,770
Increase in long-term debt	$ (731,735)

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Fresh Start Accounting - Liabilities Subject to Compromise Settled (Details) - USD ($) $ in Thousands		9 Months Ended	12 Months Ended
	Oct. 01, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Cash proceeds from building mortgage	$ 26,847
Write-off of prepaid accounts upon emergence	8,218	$ 8,218
Principal value of long-term debt issued and reinstated at emergence	(731,735)	(731,735)
Release of stockholder receivable	(1,250)	(1,250)
Application of deposit held by utility services	3,770	3,770
Predecessor
Fresh-Start Adjustment [Line Items]
Liabilities subject to compromise of the Predecessor	4,346,188	4,346,188
Cash proceeds from building mortgage		26,847	$ 0	$ 0
Predecessor | Reorganization Adjustments
Fresh-Start Adjustment [Line Items]
Current maturities of long-term debt and accrued interest	4,179,483	4,179,483
Accounts payable and accrued expenses	157,422	157,422
Other long-term liabilities	9,283	9,283
Liabilities subject to compromise of the Predecessor	4,346,188	4,346,188
Cash payments at emergence	(72,385)
Cash proceeds from building mortgage	26,847
Write-off of prepaid accounts upon emergence	(8,218)	(8,218)
Accrual for future reimbursement from professional fees escrow account and other receivables	12,356	12,356
Fair value of equity issued	(827,424)	(827,424)
Principal value of long-term debt issued and reinstated at emergence	(731,735)	(731,735)
Reinstatement of liabilities subject to compromise as accounts payable and accrued expenses	(37,789)	(37,789)
Release of stockholder receivable	(1,250)	(1,250)
Application of deposit held by utility services	3,770	3,770
Gain on settlement of liabilities subject to compromise	$ 2,702,820	$ 2,702,820

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Fresh Start Accounting - Reorganization Adjustments to Equity (Details) - Reorganization Adjustments $ / shares in Units, $ in Thousands	Oct. 01, 2016 USD ($) $ / shares
Debtor Reorganization Adjustments, Equity [Abstract]
Par value of 18.9 million shares of New Common Stock issued to former holders of the Senior Secured Notes and Unsecured Notes (valued at $29.31 per share)	$ 19
Fair value of warrants issued to holders of the Unsecured Notes	88,382
Additional paid-in capital	739,023
Total Successor Company equity issued on Emergence Date	$ 827,424
Warrants
Fair Value Assumptions and Methodology for Assets and Liabilities [Abstract]
Expected volatility rate	59.26%
Risk free interest rate	1.36%
Term	6 years
New Common Stock
Debtor Reorganization Adjustments, Equity [Abstract]
Additional paid-in capital	$ 575,144
New Convertible Notes
Debtor Reorganization Adjustments, Equity [Abstract]
Additional paid-in capital	$ 163,879
Series A Warrants | Warrants
Fair Value Assumptions and Methodology for Assets and Liabilities [Abstract]
Exercise price per share | $ / shares	$ 41.34
Series B Warrants | Warrants
Fair Value Assumptions and Methodology for Assets and Liabilities [Abstract]
Exercise price per share | $ / shares	$ 42.03
Convertible Debt | New Convertible Notes
Fair Value Assumptions and Methodology for Assets and Liabilities [Abstract]
Expected volatility rate	56.06%
Risk free interest rate	1.08%
Term	4 years
Recovery rate	15.00%
Hazard rate	12.41%
Drop on default (percent)	100.00%
Fair value of debt	$ 445,700
Face amount of debt instrument	$ 281,800

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Fresh Start Accounting - Fresh Start Adjustments (Details) $ in Thousands	Oct. 02, 2016 USD ($)
Successor
Fresh-Start Adjustment [Line Items]
Accumulated deficit	$ 0

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Fresh Start Accounting - Reorganization Items (Details) - Predecessor - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Schedule of Reorganization Items [Line Items]
Unamortized long-term debt	$ 3,546,847
Litigation claims	(20,478)
Rejections and cures of executory contracts	(16,038)
Ad valorem and franchise taxes	(3,494)
Legal and professional fees and expenses	(44,920)
Write off of director and officer insurance policy	(7,533)
Gain on accounts payable settlements	84,228
Loss on mortgage	(8,153)
Gain on preferred stock dividends	37,893
Fresh start valuation adjustments	(28,549)
Fair value of equity issued	(827,424)
Principal value of New Convertible Notes issued	(281,780)
Gain on reorganization items, net	$ 2,430,599	$ 0	$ 0

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Summary of Significant Accounting Policies - Narrative (Details) - USD ($)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014	Apr. 20, 2016	Mar. 11, 2016	Jun. 30, 2015
Senior credit facility
Significant Accounting Policies [Line Items]
Line of credit facility, current borrowing capacity					$ 500,000,000	$ 340,000,000
Successor
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		$ 0
Capitalized costs	$ 38,062,000
Maximum reserves sold from cost center not expected to result in significant alteration (less than)	25.00%
Natural gas balancing liability	$ 1,700,000
Successor | Internal Costs
Significant Accounting Policies [Line Items]
Capitalized costs	$ 4,000,000
Successor | Buildings | Minimum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	10 years
Successor | Buildings | Maximum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	39 years
Successor | Equipment | Minimum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	2 years
Successor | Equipment | Maximum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	30 years
Successor | Secured Debt | 8.75% Senior Secured Notes due 2020
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	0.00%
Successor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	0.00%
Successor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	0.00%
Successor | Oil, natural gas and NGL revenues
Significant Accounting Policies [Line Items]
Transportation costs	$ 7,400,000
Predecessor
Significant Accounting Policies [Line Items]
Capitalized costs		156,954,000	$ 846,300,000	$ 1,526,484,000
Natural gas balancing liability			1,500,000
Predecessor | Internal Costs
Significant Accounting Policies [Line Items]
Capitalized costs		22,700,000	45,100,000	55,400,000
Predecessor | Oil And Gas Unproved Properties
Significant Accounting Policies [Line Items]
Interest capitalized during period		$ 2,200,000	10,800,000	14,700,000
Predecessor | Midstream And Corporate Assets
Significant Accounting Policies [Line Items]
Interest capitalized during period			$ 3,300,000	5,000,000
Predecessor | 8.125% Convertible Senior Notes due 2022
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate			8.125%
Predecessor | 7.5% Convertible Senior Notes due 2023
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate			7.50%
Predecessor | Secured Debt | 8.75% Senior Secured Notes due 2020
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate		8.75%	8.75%				8.75%
Predecessor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate		8.125%	8.125%
Predecessor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%
Predecessor | Production expenses
Significant Accounting Policies [Line Items]
Transportation costs		$ 26,200,000	$ 45,300,000	$ 35,600,000

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Summary of Significant Accounting Policies - Concentration Risk (Details) - USD ($) $ in Thousands		3 Months Ended								9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Concentration Risk [Line Items]
Sales		$ 98,456
Successor | Plains Marketing, L.P.
Concentration Risk [Line Items]
Sales		$ 32,022
Percentage of revenue		32.50%
Successor | Targa Pipeline Mid-Continent West OK LLC
Concentration Risk [Line Items]
Sales		$ 35,845
Percentage of revenue		36.40%
Predecessor
Concentration Risk [Line Items]
Sales	$ 0		$ 104,056	$ 99,421	$ 90,332	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 293,809	$ 768,709	$ 1,558,758
Predecessor | Plains Marketing, L.P.
Concentration Risk [Line Items]
Sales										$ 110,370	$ 318,018	$ 597,117
Percentage of revenue										37.60%	41.40%	38.30%
Predecessor | Targa Pipeline Mid-Continent West OK LLC
Concentration Risk [Line Items]
Sales										$ 108,238	$ 231,649	$ 333,027
Percentage of revenue										36.80%	30.10%	21.40%

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Summary of Significant Accounting Policies - Recent Accounting Standards (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 02, 2016	Jan. 01, 2016	Dec. 31, 2015
Adjustment for Early Adoption
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Cash collateral	$ 52,800	$ 52,800
Predecessor
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Assets				$ 2,922,027
Noncontrolling interest				510,184
Retained earnings				(6,992,697)
Predecessor | ASU 2015-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Assets			$ (243,400)
Noncontrolling interest			(510,200)
Accounts payable			9,700
Retained earnings			$ 257,100
Predecessor | Other Assets | ASU 2015-03
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt issuance costs				(69,100)
Predecessor | Current maturities of long-term debt | ASU 2015-03
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Debt issuance costs				$ (69,100)

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items	$ 0
Cash paid for interest, net of amounts capitalized	(1,183)
Cash (paid) received for income taxes	0
Supplemental Disclosure of Noncash Investing and Financing Activities
Cumulative effect of adoption of ASU 2015-02	0
Property, plant and equipment transferred in settlement of contract	0
Change in accrued capital expenditures	10,630
Equity issued for debt	(13,001)
Preferred stock dividends paid in common stock	0
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$ 0
Predecessor
Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items		$ (55,606)	$ 0	$ 0
Cash paid for interest, net of amounts capitalized		(104,609)	(296,386)	(235,793)
Cash (paid) received for income taxes		(28)	(88)	1,928
Supplemental Disclosure of Noncash Investing and Financing Activities
Cumulative effect of adoption of ASU 2015-02		(247,566)	0	0
Property, plant and equipment transferred in settlement of contract		215,635	0	0
Change in accrued capital expenditures		25,045	177,586	(55,557)
Equity issued for debt		(4,409)	(63,299)	0
Preferred stock dividends paid in common stock		0	(16,188)	0
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement		$ 0	$ (50,310)	$ 0

XML

Acquisitions and Divestitures - Acquisitions (Details) - Predecessor $ in Thousands	1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2015 USD ($) a well	Oct. 31, 2015 USD ($) mi	Mar. 31, 2016 USD ($)	Oct. 01, 2016 USD ($)	Dec. 31, 2015 USD ($) a well	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Payments to acquire oil and gas property and equipment				$ 1,328	$ 216,943	$ 18,384
Loss on termination of the gathering contract			$ 89,100	$ 90,184	$ 50,976	$ 0
Pinon Gathering Company LLC
Business Acquisition [Line Items]
Payments to acquire oil and gas property and equipment		$ 48,000
Principal amount of debt issued related to acquisition		$ 78,000
Number of miles of gathering lines acquired | mi		370
Fair value of consideration paid for acquisition		$ 98,300
Loss on termination of the gathering contract		51,000
Rockies Properties | North Park Basin, Jackson County, Colorado
Business Acquisition [Line Items]
Payments to acquire oil and gas property and equipment	$ 191,100
Number acres acquired | a	135,000				135,000
Proceeds from sale of oil and natural gas properties	$ 3,100
Number of wells acquired | well	16				16
Oil and Gas Properties | Pinon Gathering Company LLC
Business Acquisition [Line Items]
Fair value of assets acquired		$ 47,300
Senior Notes | 8.75% Senior Notes due 2020
Business Acquisition [Line Items]
Long-term debt, fixed interest rate	8.75%			8.75%	8.75%

XML

Acquisitions and Divestitures - Divestitures (Details) - Predecessor - USD ($)				2 Months Ended	3 Months Ended							9 Months Ended	12 Months Ended
	Oct. 01, 2016	Jan. 21, 2016	Feb. 25, 2014	Feb. 25, 2014	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payment of certain contract cures and other												$ 11,000,000	$ 24,889,000	$ 0
Loss on termination of the gathering contract							$ 89,100,000					90,184,000	50,976,000	0
Revisions in estimated cash flows												0	44,060,000	(5,848,000)
Revenues	$ 0				$ 104,056,000	$ 99,421,000	$ 90,332,000	$ 143,642,000	$ 180,152,000	$ 229,607,000	$ 215,308,000	293,809,000	768,709,000	1,558,758,000
Expenses												$ 1,200,012,000	$ 5,411,387,000	$ 968,534,000
WTO Properties | Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payment of certain contract cures and other		$ 11,000,000
Gulf Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and natural gas properties			$ 702,600,000
Loss on sale of oil and gas property			$ 0
Guarantee period for certain plugging and abandonment obligations (up to)			1 year
Contingent liability equal to fair value of guarantees recorded as part of sale			$ 9,400,000	$ 9,400,000
Restricted deposits previously held in escrow, cash received											$ 12,000,000
Revenues				90,900,000
Expenses				63,700,000
Asset Retirement Obligations | Gulf Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset retirement obligations assumed			$ 366,000,000	$ 366,000,000
Treating Agreement | WTO Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revisions in estimated cash flows		$ (34,100,000)
Treating Agreement | WTO Properties | Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Contract agreement, term		30 years
Cumulative shortfall accrued		$ 111,900,000
Loss on termination of the gathering contract		$ 89,100,000

XML

Fair Value Measurements - Narrative (Details) - Predecessor - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2015
Level 2 | Senior Notes | 8.75% Senior Notes due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Write off of derivative holder conversion feature to reorganization items	$ 2,500
Level 3 | Gulf Properties
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Estimate of future payments for plugging and abandonment		$ 372,000
Long-term Debt Holder Conversion Feature
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Write off of derivative holder conversion feature to reorganization items	$ 7,281	$ 0

XML

Fair Value Measurements - Significant Unobservable Inputs - Long Term Debt Conversion Feature (Details) - Debt holder conversion feature - Level 3 $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Fair value	$ 29,355
Minimum
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Hazard rate	114.00%
Maximum
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Hazard rate	135.20%
Weighted Average
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Hazard rate	119.20%

XML

Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative assets	$ 0
Derivative Liabilities	29,714
Successor | Recurring Measurement Basis
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments	7,541
Assets	7,541
Derivative Liabilities, Netting	0
Derivative Liabilities at Fair Value	29,714
Successor | Recurring Measurement Basis | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities, Netting	0
Derivative Liabilities at Fair Value	29,714
Successor | Recurring Measurement Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments	7,541
Assets	7,541
Derivative Liabilities	0
Successor | Recurring Measurement Basis | Level 1 | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities	0
Successor | Recurring Measurement Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments	0
Assets	0
Derivative Liabilities	29,714
Successor | Recurring Measurement Basis | Level 2 | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities	29,714
Successor | Recurring Measurement Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments	0
Assets	0
Derivative Liabilities	0
Successor | Recurring Measurement Basis | Level 3 | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities	$ 0
Predecessor
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative assets		$ 85,524
Derivative Liabilities		1,748
Predecessor | Recurring Measurement Basis
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments		10,106
Assets		94,455
Derivative Assets, Netting		(1,175)
Derivative Liabilities, Netting		(1,175)
Derivative Liabilities at Fair Value		32,869
Predecessor | Recurring Measurement Basis | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Assets, Netting		(1,175)
Derivative Assets at Fair Value		84,349
Derivative Liabilities, Netting		(1,175)
Derivative Liabilities at Fair Value		573
Predecessor | Recurring Measurement Basis | Debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities, Netting		0
Derivative Liabilities at Fair Value		29,355
Predecessor | Recurring Measurement Basis | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities, Netting		0
Derivative Liabilities at Fair Value		2,941
Predecessor | Recurring Measurement Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments		10,106
Assets		10,106
Derivative Liabilities		0
Predecessor | Recurring Measurement Basis | Level 1 | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative assets		0
Derivative Liabilities		0
Predecessor | Recurring Measurement Basis | Level 1 | Debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities		0
Predecessor | Recurring Measurement Basis | Level 1 | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities		0
Predecessor | Recurring Measurement Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments		0
Assets		85,524
Derivative Liabilities		2,941
Predecessor | Recurring Measurement Basis | Level 2 | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative assets		85,524
Derivative Liabilities		0
Predecessor | Recurring Measurement Basis | Level 2 | Debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities		0
Predecessor | Recurring Measurement Basis | Level 2 | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities		2,941
Predecessor | Recurring Measurement Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring Basis
Investments		0
Assets		0
Derivative Liabilities		31,103
Predecessor | Recurring Measurement Basis | Level 3 | Commodity derivative contracts
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative assets		0
Derivative Liabilities		1,748
Predecessor | Recurring Measurement Basis | Level 3 | Debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities		29,355
Predecessor | Recurring Measurement Basis | Level 3 | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative Liabilities		$ 0

XML

Fair Value Measurements - Reconciliation of Fair Value Measurements for Long-Term Debt Holder Conversion Feature (Details) - Predecessor - Debt holder conversion feature - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2015
Level 3 Fair Value Measurements - Long-Term Debt Holder Conversion Feature
Beginning balance	$ 29,355	$ 0
Issuances	0	31,200
(Loss) gain on derivative holder conversion feature	(880)	10,198
Conversions	(21,194)	(12,043)
Write off of derivative holder conversion feature to reorganization items	(7,281)	0
Ending balance	$ 0	$ 29,355

XML

Fair Value Measurements - Estimated Fair Value and Carrying Value of Senior Notes (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Jun. 30, 2015
Convertible Debt | New Convertible Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value	$ 268,780
Successor
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value	305,308
Successor | Secured Debt | New Building Note
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value		$ 36,600
Carrying Value	$ 36,528
Successor | Secured Debt | 8.75% Senior Secured Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Carrying Value	$ 0
Successor | Senior Notes | 8.75% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Carrying Value	$ 0
Successor | Senior Notes | 7.5% Senior Notes due 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Carrying Value	$ 0
Successor | Senior Notes | 8.125% Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Carrying Value	$ 0
Successor | Senior Notes | 7.5% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Carrying Value	$ 0
Successor | Convertible Debt | New Convertible Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value		$ 445,700
Carrying Value	$ 268,780
Successor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Carrying Value	$ 0
Successor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Carrying Value	$ 0
Successor | Level 2 | Secured Debt | New Building Note
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	$ 40,608
Successor | Level 2 | Secured Debt | 8.75% Senior Secured Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Fair Value	$ 0
Successor | Level 2 | Senior Notes | 8.75% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Fair Value	$ 0
Successor | Level 2 | Senior Notes | 7.5% Senior Notes due 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Fair Value	$ 0
Successor | Level 2 | Senior Notes | 8.125% Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Fair Value	$ 0
Successor | Level 2 | Senior Notes | 7.5% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Fair Value	$ 0
Successor | Level 2 | Convertible Debt | New Convertible Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value	$ 334,800
Successor | Level 2 | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Fair Value	$ 0
Successor | Level 2 | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate	0.00%
Fair Value	$ 0
Predecessor
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value			$ 3,562,378
Predecessor | 8.125% Convertible Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			8.125%
Predecessor | 7.5% Convertible Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			7.50%
Predecessor | Secured Debt | New Building Note
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value			$ 0
Predecessor | Secured Debt | 8.75% Senior Secured Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate		8.75%	8.75%	8.75%
Carrying Value			$ 1,265,814
Predecessor | Senior Notes | 8.75% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate		8.75%	8.75%
Carrying Value			$ 389,232
Predecessor | Senior Notes | 7.5% Senior Notes due 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%
Carrying Value			$ 751,087
Predecessor | Senior Notes | 8.125% Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate		8.125%	8.125%
Carrying Value			$ 518,693
Predecessor | Senior Notes | 7.5% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%
Carrying Value			$ 534,869
Predecessor | Convertible Debt | New Convertible Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Value			$ 0
Predecessor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate		8.125%	8.125%
Carrying Value			$ 78,290
Predecessor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%
Carrying Value			$ 24,393
Predecessor | Level 2 | Secured Debt | New Building Note
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value			$ 0
Predecessor | Level 2 | Secured Debt | 8.75% Senior Secured Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			8.75%
Fair Value			$ 403,098
Predecessor | Level 2 | Senior Notes | 8.75% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			8.75%
Fair Value			$ 39,740
Predecessor | Level 2 | Senior Notes | 7.5% Senior Notes due 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			7.50%
Fair Value			$ 79,812
Predecessor | Level 2 | Senior Notes | 8.125% Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			8.125%
Fair Value			$ 57,749
Predecessor | Level 2 | Senior Notes | 7.5% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			7.50%
Fair Value			$ 58,799
Predecessor | Level 2 | Convertible Debt | New Convertible Notes
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value			$ 0
Predecessor | Level 2 | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			8.125%
Fair Value			$ 44,199
Predecessor | Level 2 | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fixed interest rate			7.50%
Fair Value			$ 15,125

XML

Accounts Receivable - Summary of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil, natural gas and NGL sales	$ 42,631
Joint interest billing	17,338
Oil and natural gas services	736
Other	14,272
Total accounts receivable	74,977
Less: allowance for doubtful accounts	(880)	$ 0
Total accounts receivable, net	$ 74,097
Predecessor
Accounts, Notes, Loans and Financing Receivable [Line Items]
Oil, natural gas and NGL sales			$ 61,140
Joint interest billing			60,403
Oil and natural gas services			2,417
Other			8,274
Total accounts receivable			132,234
Less: allowance for doubtful accounts		$ 0	(4,847)	$ (7,083)	$ (11,061)
Total accounts receivable, net			$ 127,387

XML

Accounts Receivable - Balance and Activity in Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	$ 0
Provision for doubtful accounts	880
Deductions	0
Impact of fresh start accounting	0
Ending balance	880	$ 0
Predecessor
Accounts, Notes, Loans and Financing Receivable [Line Items]
Beginning balance	$ 0	4,847	$ 7,083	$ 11,061
Provision for doubtful accounts		16,695	1,320	818
Deductions		(751)	(3,556)	(4,796)
Impact of fresh start accounting		(20,791)	0	0
Ending balance		$ 0	$ 4,847	$ 7,083

XML

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Oil and natural gas properties, using full cost method of accounting
Proved	$ 840,201
Unproved	74,937
Total oil and natural gas properties	915,138
Less: accumulated depreciation, depletion and impairment	(353,030)
Net oil and natural gas properties capitalized costs	562,108
Land	5,100
Non-oil and natural gas equipment	166,010
Buildings and structures	88,603
Total	259,713
Less accumulated depreciation and amortization	(3,889)
Other property, plant and equipment, net	255,824
Total property, plant and equipment, net	$ 817,932
Predecessor
Oil and natural gas properties, using full cost method of accounting
Proved		$ 12,529,681	$ 11,707,147
Unproved		363,149	290,596
Total oil and natural gas properties		12,892,830	11,997,743
Less: accumulated depreciation, depletion and impairment		(11,149,888)	(6,359,149)
Net oil and natural gas properties capitalized costs		1,742,942	$ 5,638,594
Land		14,260
Non-oil and natural gas equipment		373,687
Buildings and structures		227,673
Total		615,620
Less accumulated depreciation and amortization		(123,860)
Other property, plant and equipment, net		491,760
Total property, plant and equipment, net		2,234,702
Predecessor | Oil and gas proved properties
Oil and natural gas properties, using full cost method of accounting
Cumulative capitalized interest		48,900
Predecessor | Non-oil and natural gas equipment
Oil and natural gas properties, using full cost method of accounting
Cumulative capitalized interest		4,300
Predecessor | Buildings
Oil and natural gas properties, using full cost method of accounting
Cumulative capitalized interest		$ 20,400

XML

Property, Plant and Equipment - Narrative (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016 USD ($) $ / Boe	Oct. 01, 2016 USD ($) $ / Boe	Dec. 31, 2015 USD ($) $ / Boe	Dec. 31, 2014 USD ($) well $ / Boe	Jun. 30, 2015 USD ($)	May 31, 2015 USD ($) well
Predecessor
Property, Plant and Equipment [Line Items]
Cumulative full cost ceiling limitation impairment charges			$ 8,200,000,000
Full cost ceiling impairments		$ 657,392,000	$ 4,473,787,000	$ 164,779,000
Average depreciation and depletion rate (usd per Boe) | $ / Boe		5.76	10.67	15.00
Predecessor | Repsol
Property, Plant and Equipment [Line Items]
Drilling carry received or billed				$ 205,600,000
Predecessor | Repsol
Property, Plant and Equipment [Line Items]
Minimum net wells | well				484
Net wells | well						453
Costs incurred toward satisfaction of obligation		$ 6,200,000	$ 16,100,000
Predecessor | Repsol | Potential Drilling Carry Costs
Property, Plant and Equipment [Line Items]
Repsol's future drilling and completion costs, per well				$ 1,000,000
Future drilling and completion costs				$ 75,000,000.0		$ 31,000,000
Predecessor | Drilling and Oil Field Services
Property, Plant and Equipment [Line Items]
Other operating expenses			3,500,000
Predecessor | Drilling And Oil Field Services Assets
Property, Plant and Equipment [Line Items]
Assets held for sale			$ 16,000,000		$ 20,000,000
Successor
Property, Plant and Equipment [Line Items]
Full cost ceiling impairments	$ 319,087,000
Average depreciation and depletion rate (usd per Boe) | $ / Boe	7.82
Expected completion of evaluation activities on majority of unproved properties	10 years
Successor | Repsol
Property, Plant and Equipment [Line Items]
Bankruptcy claims settled	$ 1,200,000
Successor | Drilling And Oil Field Services Assets
Property, Plant and Equipment [Line Items]
Assets held for sale	$ 0

XML

Property, Plant and Equipment - Capitalized Costs of Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Property, Plant and Equipment [Line Items]
Property acquisition, cumulative	$ 71,171
Property acquisition	7,390
Exploration, cumulative	20,459
Exploration	2,123
Total costs incurred, cumulative	91,630
Total costs incurred	9,513
Pipe inventory costs, cumulative	16,700
Pipe inventory costs, period costs	$ 2,100
Predecessor
Property, Plant and Equipment [Line Items]
Property acquisition, cumulative				$ 10,052
Property acquisition		$ 18,959	$ 34,770
Exploration, cumulative				3,080
Exploration		10,578	4,678
Total costs incurred, cumulative				$ 13,132
Total costs incurred		29,537	39,448
Pipe inventory costs, period costs		$ 9,600	$ 5,000

XML

Impairment - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended								9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Full cost pool ceiling impairments	$ 319,087
Asset impairment charges	319,087
Other property, plant and equipment, net	255,824
Successor | Drilling assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges	0
Successor | Electric transmission assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges	0
Successor | Midstream assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges	0
Successor | Other
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges	$ 0
Predecessor
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Full cost pool ceiling impairments									$ 657,392	$ 4,473,787	$ 164,779
Asset impairment charges		$ 354,500	$ 253,600	$ 110,100	$ 886,800	$ 1,100,000	$ 1,500,000	$ 1,100,000	718,194	4,534,689	192,768
Other property, plant and equipment, net					$ 491,760					491,760
Predecessor | Drilling assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges									3,511	37,646	27,428
Predecessor | Electric transmission assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges									55,600	0	0
Predecessor | Midstream assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges									1,691	7,148	561
Predecessor | Other
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges									$ 0	16,108	0
Predecessor | Permian Region | Drilling assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges											$ 24,300
Predecessor | Oklahoma City, Oklahoma | Other
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges										$ 15,400

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Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Schedule of Accounts Payable and Accrued Liabilities [Line Items]
Accounts payable and other accrued expenses	$ 65,408
Accrued interest	648
Production payable	16,011
Payroll and benefits	33,606
Convertible perpetual preferred stock dividends	0
Drilling advances	844
Related party	0
Total accounts payable and accrued expenses	$ 116,517
Predecessor
Schedule of Accounts Payable and Accrued Liabilities [Line Items]
Accounts payable and other accrued expenses		$ 231,697
Accrued interest		73,320
Production payable		55,260
Payroll and benefits		42,728
Convertible perpetual preferred stock dividends		21,572
Drilling advances		2,295
Related party		1,545
Total accounts payable and accrued expenses		$ 428,417

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Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Jun. 30, 2015
Convertible Debt | New Convertible Notes
Debt Instrument [Line Items]
Total debt	$ 268,780
Successor
Debt Instrument [Line Items]
Total debt	305,308
Less: current maturities of long-term debt	0
Long-term debt	305,308
Successor | Revolving Credit Facility | New First Lien Exit Facility
Debt Instrument [Line Items]
Total debt	0
Successor | Senior credit facility
Debt Instrument [Line Items]
Total debt	0
Successor | Secured Debt | New Building Note
Debt Instrument [Line Items]
Total debt	$ 36,528
Successor | Secured Debt | 8.75% Senior Secured Notes due 2020
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	0.00%
Total debt	$ 0
Successor | Senior Notes | 8.75% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	0.00%
Total debt	$ 0
Successor | Senior Notes | 7.5% Senior Notes due 2021
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	0.00%
Total debt	$ 0
Successor | Senior Notes | 8.125% Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	0.00%
Total debt	$ 0
Successor | Senior Notes | 7.5% Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	0.00%
Total debt	$ 0
Successor | Convertible Debt | New Convertible Notes
Debt Instrument [Line Items]
Total debt	$ 268,780
Successor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	0.00%
Total debt	$ 0
Successor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	0.00%
Total debt	$ 0
Predecessor
Debt Instrument [Line Items]
Total debt			$ 3,562,378
Less: current maturities of long-term debt			0
Long-term debt			$ 3,562,378
Predecessor | 8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate			8.125%
Predecessor | 7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate			7.50%
Predecessor | Revolving Credit Facility | New First Lien Exit Facility
Debt Instrument [Line Items]
Total debt			$ 0
Predecessor | Senior credit facility
Debt Instrument [Line Items]
Total debt			0
Predecessor | Secured Debt | New Building Note
Debt Instrument [Line Items]
Total debt			$ 0
Predecessor | Secured Debt | 8.75% Senior Secured Notes due 2020
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		8.75%	8.75%	8.75%
Total debt			$ 1,265,814
Predecessor | Senior Notes | 8.75% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		8.75%	8.75%
Total debt			$ 389,232
Predecessor | Senior Notes | 7.5% Senior Notes due 2021
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%
Total debt			$ 751,087
Predecessor | Senior Notes | 8.125% Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		8.125%	8.125%
Total debt			$ 518,693
Predecessor | Senior Notes | 7.5% Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%
Total debt			$ 534,869
Predecessor | Convertible Debt | New Convertible Notes
Debt Instrument [Line Items]
Total debt			$ 0
Predecessor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		8.125%	8.125%
Total debt			$ 78,290
Predecessor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%
Total debt			$ 24,393

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Long-Term Debt - Narrative (Details) $ / shares in Units, shares in Millions			1 Months Ended	3 Months Ended		9 Months Ended	12 Months Ended
	Oct. 01, 2016 USD ($) shares $ / shares	May 11, 2016 USD ($)	Jun. 30, 2015 USD ($)	Dec. 31, 2016 USD ($) shares	Mar. 31, 2016 USD ($)	Oct. 01, 2016 USD ($) shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($)	Apr. 20, 2016 USD ($)	Mar. 11, 2016 USD ($)	Oct. 31, 2015 USD ($)	Oct. 16, 2015 USD ($)
Senior credit facility
Debt Instrument [Line Items]
Letters of credit outstanding				$ 8,600,000
Line of credit facility, current borrowing capacity									$ 500,000,000	$ 340,000,000
Convertible Debt | New Convertible Notes
Debt Instrument [Line Items]
Face value of long-term debt				268,780,000
Revolving Credit Facility | New First Lien Exit Facility
Debt Instrument [Line Items]
Maximum borrowing capacity	$ 425,000,000					$ 425,000,000
Revolving Credit Facility | New First Lien Exit Facility | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	4.75%
Variable rate floor	1.00%
Successor
Debt Instrument [Line Items]
Face value of long-term debt				305,308,000
Common stock issued for debt				13,001,000
Repayments of debt				0
Gain on extinguishment of debt				0
Write off of debt issuance costs				0
Long-term debt maturing in 2020				268,800,000
Long-term debt maturing in 2021				35,000,000
Successor | Senior credit facility
Debt Instrument [Line Items]
Face value of long-term debt				0
Successor | Secured Debt | New Building Note
Debt Instrument [Line Items]
Face value of long-term debt				$ 36,528,000
Face amount of debt instrument	$ 35,000,000.0					35,000,000.0
Fair value of debt	$ 36,600,000					$ 36,600,000
Effective interest rate				10.90%
Interest payment period number of days after refinancing	90 days
Proceeds from issuance of debt	$ 26,800,000
Term	46 months
Successor | Secured Debt | 8.75% Senior Secured Notes due 2020
Debt Instrument [Line Items]
Face value of long-term debt				$ 0
Long-term debt, fixed interest rate				0.00%
Successor | Secured Debt | October 5, 2016 through October 4, 2017 | New Building Note
Debt Instrument [Line Items]
Annual interest rate	6.00%					6.00%
Successor | Secured Debt | October 5, 2017 through October 4, 2018 | New Building Note
Debt Instrument [Line Items]
Annual interest rate	8.00%					8.00%
Successor | Secured Debt | October 5, 2018 and thereafter | New Building Note
Debt Instrument [Line Items]
Annual interest rate	10.00%					10.00%
Successor | Senior Notes | 8.75% Senior Notes due 2020
Debt Instrument [Line Items]
Face value of long-term debt				$ 0
Long-term debt, fixed interest rate				0.00%
Successor | Convertible Debt | New Convertible Notes
Debt Instrument [Line Items]
Face value of long-term debt				$ 268,780,000
Face amount of debt instrument	$ 281,800,000					$ 281,800,000
Fair value of debt	445,700,000					445,700,000
Premium on debt instrument	$ 163,900,000					$ 163,900,000
Call provision ratio	0.783478					0.783478
Conversion ratio	0.05330841
Number of shares issuable under convertible securities | shares	15.0
Proceeds from stock issuance trigger mandatory conversion	$ 100,000,000
Initial conversion price threshold (usd per share) | $ / shares	$ 34.16
Conversion written notice period	30 days
Threshold consecutive trading days	30 days
Convertible debt, threshold percentage of stock price trigger	50.00%
Common stock issued for debt				$ 13,000,000
Common stock issued for debt (in shares) | shares				0.7
Redemption price percentage	100.00%
Principal required to be secured	$ 100,000,000.0					$ 100,000,000.0
Successor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Face value of long-term debt				$ 0
Long-term debt, fixed interest rate				0.00%
Successor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Face value of long-term debt				$ 0
Long-term debt, fixed interest rate				0.00%
Successor | Revolving Credit Facility | New First Lien Exit Facility
Debt Instrument [Line Items]
Face value of long-term debt				$ 0
Maximum borrowing capacity	$ 425,000,000.0					$ 425,000,000.0
Amount of proved developed producing reserves pledged as collateral (percentage)	95.00%					95.00%
Minimum collateral amount of proved oil and gas reserves representing the discounted present value of reserves used in borrowing base determination	95.00%					95.00%
Covenant, Proved developed producing asset coverage ratio	1.75					1.75
Minimum consolidated interest coverage ratio	2.00					2.00
Successor | Revolving Credit Facility | New First Lien Exit Facility | Maximum
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage						0.50%
Successor | Revolving Credit Facility | New First Lien Exit Facility | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate	3.75%
Successor | Revolving Credit Facility | New First Lien Exit Facility | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate	4.75%
Variable rate floor	1.00%
Successor | Revolving Credit Facility | On or prior to December 31, 2018 | New First Lien Exit Facility
Debt Instrument [Line Items]
Maximum consolidated net leverage ratio	3.50					3.50
Successor | Revolving Credit Facility | On or After March 31, 2019 | New First Lien Exit Facility
Debt Instrument [Line Items]
Maximum consolidated net leverage ratio	3.00					3.00
Predecessor
Debt Instrument [Line Items]
Face value of long-term debt							$ 3,562,378,000
Unamortized discount (premium) and debt issuance costs, net							342,600,000
Embedded derivative, fair value							32,300,000
Net unamortized discount (premium) and debt issuance costs written off						$ 158,600,000
Embedded derivative written off						9,800,000
Common stock issued for debt						$ 4,409,000	$ 63,299,000	$ 0
Common stock issued for debt (in shares) | shares						84.4	92.8
Repayments of debt						$ 33,874,000	$ 0	0
Aggregate cash payments for accrued interest and early conversion of debt						33,500,000	30,500,000
Gain on extinguishment of debt					$ 41,300,000	41,179,000	641,131,000	0
Write off of debt issuance costs						0	7,108,000	$ 0
Predecessor | Conversion of Senior Notes to Common Stock
Debt Instrument [Line Items]
Gain on extinguishment of debt						41,300,000	6,100,000
Write off of debt issuance costs						4,300,000	$ 5,200,000
Predecessor | 8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate							8.125%
Predecessor | 7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate							7.50%
Predecessor | Senior credit facility
Debt Instrument [Line Items]
Debt canceled	$ 449,200,000					$ 449,200,000
Face value of long-term debt							$ 0
Minimum collateral amount of proved oil and gas reserves representing the discounted present value of reserves used in borrowing base determination	80.00%					80.00%
Number of days prior to earliest maturity date or mandatory offer of repurchase						91 days
Repayments of debt		$ 40,000,000
Predecessor | Senior credit facility | Base Rate | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate						0.75%
Predecessor | Senior credit facility | Base Rate | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate						1.75%
Predecessor | Senior credit facility | LIBOR | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate						1.75%
Predecessor | Senior credit facility | LIBOR | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate						2.75%
Predecessor | Senior credit facility | Federal Funds
Debt Instrument [Line Items]
Basis spread on variable rate						0.50%
Predecessor | Senior credit facility | One-Month Eurodollar Rate
Debt Instrument [Line Items]
Basis spread on variable rate						1.00%
Predecessor | Senior credit facility | June Amendment
Debt Instrument [Line Items]
Ratio of secured debt to EBITDA, maximum	2.00					2.00
Current assets to current liabilities, ratio minimum	1.0					1.0
Predecessor | Senior credit facility | August 2015 Amendment
Debt Instrument [Line Items]
Allowed repurchases of outstanding debt												$ 275,000,000
Predecessor | Secured Debt
Debt Instrument [Line Items]
Debt canceled	$ 1,300,000,000					$ 1,300,000,000
Predecessor | Secured Debt | New Building Note
Debt Instrument [Line Items]
Face value of long-term debt							0
Predecessor | Secured Debt | 8.75% Senior Secured Notes due 2020
Debt Instrument [Line Items]
Face value of long-term debt							$ 1,265,814,000
Face amount of debt instrument			$ 1,250,000,000.0								$ 78,000,000
Long-term debt, fixed interest rate	8.75%		8.75%			8.75%	8.75%
Proceeds from debt, net of issuance costs			$ 1,210,000,000
Fair value of notes awarded											$ 50,300,000
Predecessor | Senior Notes
Debt Instrument [Line Items]
Debt canceled	$ 2,200,000,000					$ 2,200,000,000
Predecessor | Senior Notes | 8.75% Senior Notes due 2020
Debt Instrument [Line Items]
Face value of long-term debt							$ 389,232,000
Long-term debt, fixed interest rate	8.75%					8.75%	8.75%
Mandatory prepayment feature, threshold amount of outstanding principal amount of senior notes	$ 100,000,000					$ 100,000,000
Predecessor | Convertible Debt
Debt Instrument [Line Items]
Debt canceled	$ 87,600,000					87,600,000
Debt conversion, original debt, amount						$ 232,100,000	$ 255,300,000
Predecessor | Convertible Debt | New Convertible Notes
Debt Instrument [Line Items]
Face value of long-term debt							0
Predecessor | Convertible Debt | 8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Face value of long-term debt							$ 78,290,000
Long-term debt, fixed interest rate	8.125%					8.125%	8.125%
Debt conversion, original debt, amount						$ 200,500,000	$ 186,600,000
Debt conversion, original debt aggregate principal, net of discount and including holder's conversion feature						$ 67,400,000	54,400,000
Predecessor | Convertible Debt | 7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Face value of long-term debt							$ 24,393,000
Long-term debt, fixed interest rate	7.50%					7.50%	7.50%
Debt conversion, original debt, amount						$ 31,600,000	$ 68,700,000
Debt conversion, original debt aggregate principal, net of discount and including holder's conversion feature						$ 10,400,000	19,300,000
Predecessor | Revolving Credit Facility | New First Lien Exit Facility
Debt Instrument [Line Items]
Face value of long-term debt							$ 0

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Derivatives - Offsetting Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
ASSETS
Derivative assets, gross amounts	$ 0
Derivative assets, gross amounts offset	0
Derivative assets, amounts net of offset	0
Derivative assets, financial collateral	0
Derivative assets, net amount	0
LIABILITIES
Derivative liabilities, gross amounts	29,714
Derivative liabilities, gross amounts offset	0
Derivative liabilities, amount net of offset	29,714
Derivative liabilities, financial collateral	(29,714)
Derivative liabilities, net amount	0
Successor | Derivative contracts - current
ASSETS
Derivative assets, gross amounts	0
Derivative assets, gross amounts offset	0
Derivative assets, amounts net of offset	0
Derivative assets, financial collateral	0
Derivative assets, net amount	0
Successor | Noncurrent assets
ASSETS
Derivative assets, gross amounts	0
Derivative assets, gross amounts offset	0
Derivative assets, amounts net of offset	0
Derivative assets, financial collateral	0
Derivative assets, net amount	0
Successor | Derivative contracts - current
LIABILITIES
Derivative liabilities, gross amounts	27,538
Derivative liabilities, gross amounts offset	0
Derivative liabilities, amount net of offset	27,538
Derivative liabilities, financial collateral	(27,538)
Derivative liabilities, net amount	0
Successor | Derivative contracts - noncurrent
LIABILITIES
Derivative liabilities, gross amounts	2,176
Derivative liabilities, gross amounts offset	0
Derivative liabilities, amount net of offset	2,176
Derivative liabilities, financial collateral	(2,176)
Derivative liabilities, net amount	$ 0
Predecessor
ASSETS
Derivative assets, gross amounts		$ 85,524
Derivative assets, gross amounts offset		(1,175)
Derivative assets, amounts net of offset		84,349
Derivative assets, financial collateral		0
Derivative assets, net amount		84,349
LIABILITIES
Derivative liabilities, gross amounts		1,748
Derivative liabilities, gross amounts offset		(1,175)
Derivative liabilities, amount net of offset		573
Derivative liabilities, financial collateral		(573)
Derivative liabilities, net amount		0
Predecessor | Derivative contracts - current
ASSETS
Derivative assets, gross amounts		85,524
Derivative assets, gross amounts offset		(1,175)
Derivative assets, amounts net of offset		84,349
Derivative assets, financial collateral		0
Derivative assets, net amount		84,349
Predecessor | Noncurrent assets
ASSETS
Derivative assets, gross amounts		0
Derivative assets, gross amounts offset		0
Derivative assets, amounts net of offset		0
Derivative assets, financial collateral		0
Derivative assets, net amount		0
Predecessor | Derivative contracts - current
LIABILITIES
Derivative liabilities, gross amounts		1,748
Derivative liabilities, gross amounts offset		(1,175)
Derivative liabilities, amount net of offset		573
Derivative liabilities, financial collateral		(573)
Derivative liabilities, net amount		0
Predecessor | Derivative contracts - noncurrent
LIABILITIES
Derivative liabilities, gross amounts		0
Derivative liabilities, gross amounts offset		0
Derivative liabilities, amount net of offset		0
Derivative liabilities, financial collateral		0
Derivative liabilities, net amount		$ 0

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Derivatives - Open Commodity Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2016 $ / Mcf $ / bbl MBbls Mcf
Oil Price Swaps, January 2017 - December 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional (Oil in MBbl/Natural Gas in MMcf) | MBbls	3,285
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf) | $ / bbl	52.24
Oil Price Swaps, January 2018 - December 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional (Oil in MBbl/Natural Gas in MMcf) | MBbls	1,825
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf) | $ / bbl	55.34
Natural Gas Price Swaps, January 2017 - December 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional (Oil in MBbl/Natural Gas in MMcf) | Mcf	32,850
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf) | $ / Mcf	3.20
Natural Gas Price Swaps, January 2018 - December 2018
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional (Oil in MBbl/Natural Gas in MMcf) | Mcf	3,650
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf) | $ / Mcf	3.12

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Derivatives - Fair Value of Derivative Contracts (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Successor
Derivatives, Fair Value [Line Items]
Assets	$ 0
Derivative liabilities	(29,714)
Total net derivative contracts	(29,714)
Successor | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Assets	0
Successor | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities	(27,538)
Successor | Derivative contracts - noncurrent
Derivatives, Fair Value [Line Items]
Derivative liabilities	(2,176)
Successor | Oil price swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Assets	0
Successor | Oil price swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities	(13,395)
Successor | Oil price swaps | Derivative contracts - noncurrent
Derivatives, Fair Value [Line Items]
Derivative liabilities	(2,105)
Successor | Oil collars—three way | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Assets	0
Successor | Natural gas price swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities	(14,143)
Successor | Natural gas price swaps | Derivative contracts - noncurrent
Derivatives, Fair Value [Line Items]
Derivative liabilities	(71)
Successor | Natural gas basis swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities	0
Successor | Debt holder conversion feature | Current maturities of long-term debt
Derivatives, Fair Value [Line Items]
Derivative liabilities	0
Successor | Mandatory prepayment feature - PGC Senior Secured Notes | Current maturities of long-term debt
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ 0
Predecessor
Derivatives, Fair Value [Line Items]
Assets		$ 85,524
Derivative liabilities		(1,748)
Total net derivative contracts		51,480
Predecessor | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Assets		85,524
Predecessor | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities		(1,748)
Predecessor | Derivative contracts - noncurrent
Derivatives, Fair Value [Line Items]
Derivative liabilities		0
Predecessor | Oil price swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Assets		68,224
Predecessor | Oil price swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities		0
Predecessor | Oil price swaps | Derivative contracts - noncurrent
Derivatives, Fair Value [Line Items]
Derivative liabilities		0
Predecessor | Oil collars—three way | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Assets		17,300
Predecessor | Natural gas price swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities		0
Predecessor | Natural gas price swaps | Derivative contracts - noncurrent
Derivatives, Fair Value [Line Items]
Derivative liabilities		0
Predecessor | Natural gas basis swaps | Derivative contracts - current
Derivatives, Fair Value [Line Items]
Derivative liabilities		(1,748)
Predecessor | Debt holder conversion feature | Current maturities of long-term debt
Derivatives, Fair Value [Line Items]
Derivative liabilities		(29,355)
Predecessor | Mandatory prepayment feature - PGC Senior Secured Notes | Current maturities of long-term debt
Derivatives, Fair Value [Line Items]
Derivative liabilities		$ (2,941)

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Derivatives - Narrative (Details)	3 Months Ended						9 Months Ended	12 Months Ended
	Dec. 31, 2016 USD ($) institution	Jun. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Oct. 01, 2016 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Successor
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (gain) on derivative contracts	$ 25,652,000
Cash (receipts) payments on early settlement	$ (7,698,000)
Number of counterparties to open derivative contracts | institution	4
Successor | Commodity Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (gain) on derivative contracts	$ 25,700,000
Cash (receipts) payments on settlement	$ (7,700,000)
Successor | Senior Notes | 8.75% Senior Notes due 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Long-term debt, fixed interest rate	0.00%
Predecessor
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (gain) on derivative contracts			$ (14,000,000)	$ (42,200,000)	$ 33,000,000	$ (49,800,000)	$ 4,823,000	$ (73,061,000)	$ (334,011,000)
Cash (receipts) payments on early settlement							(72,608,000)	(327,702,000)	(11,796,000)
Predecessor | Commodity Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (gain) on derivative contracts							4,800,000	(73,100,000)	(334,000,000)
Cash (receipts) payments on settlement							$ (72,600,000)	$ (327,700,000)	32,300,000
Cash (receipts) payments on early settlement		$ (17,900,000)							$ (69,900,000)
Predecessor | Senior Notes | 8.75% Senior Notes due 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Long-term debt, fixed interest rate			8.75%				8.75%	8.75%
Mandatory prepayment feature, threshold amount of outstanding principal amount of senior notes							$ 100,000,000

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Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Asset Retirement Obligation, Roll Forward Analysis
Beginning balance	$ 92,413
Liability incurred upon acquiring and drilling wells	121
Revisions in estimated cash flows	12,397
Liability settled or disposed in current period	(540)
Accretion	2,090
Impact of fresh start accounting	0
Ending balance	106,481	$ 92,413
Less: current portion	66,154
Asset retirement obligations, net of current	40,327
Predecessor
Asset Retirement Obligation, Roll Forward Analysis
Beginning balance	$ 92,413	103,578	$ 54,402	$ 424,117
Liability incurred upon acquiring and drilling wells		505	1,662	4,968
Revisions in estimated cash flows		0	44,060	(5,848)
Liability settled or disposed in current period		(36,979)	(1,023)	(377,927)
Accretion		4,365	4,477	9,092
Impact of fresh start accounting		20,944	0	0
Ending balance		92,413	103,578	54,402
Less: current portion		65,678	8,399	0
Asset retirement obligations, net of current		26,735	$ 95,179	54,402
Predecessor | WTO Properties
Asset Retirement Obligation, Roll Forward Analysis
Liability settled or disposed in current period		$ (34,100)
Predecessor | Gulf of Mexico Properties
Asset Retirement Obligation, Roll Forward Analysis
Liability settled or disposed in current period				$ (366,000)

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Commitments and Contingencies - Narrative (Details) - USD ($) $ in Thousands			3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 20, 2016	Jun. 16, 2016	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Predecessor
Commitments and Contingencies Disclosure [Line Items]
Employee termination benefits				$ 18,356	$ 12,451	$ 8,874
Estimated litigation claims				20,478
Predecessor | SEC
Commitments and Contingencies Disclosure [Line Items]
Amount of claims filed under bankruptcy		$ 1,200
Estimated liability				1,400
Successor
Commitments and Contingencies Disclosure [Line Items]
Employee termination benefits			$ 12,334
Successor | SEC
Commitments and Contingencies Disclosure [Line Items]
Estimated liability			100
Settlement amount	$ 1,400
Employee Severance | Predecessor
Commitments and Contingencies Disclosure [Line Items]
Employee termination benefits				$ 18,400
Employee Severance | Successor
Commitments and Contingencies Disclosure [Line Items]
Employee termination benefits			12,300
Employee termination benefits payable			$ 5,700
Gulf Properties | Employee Severance | Predecessor
Commitments and Contingencies Disclosure [Line Items]
Employee termination benefits					$ 12,500	$ 8,900

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Equity - Successor Equity (Details) - USD ($) $ / shares in Units, $ in Thousands		9 Months Ended	12 Months Ended
	Oct. 01, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2016	Jun. 30, 2015
Successor
Class of Stock [Line Items]
Common stock, issued (in shares)	18,900,000	18,900,000		19,635,000
Common stock, par value (in dollars per share)				$ 0.001
Shares authorized (in shares)				250,000,000
Additional paid-in capital - stockholder receivable				$ 0
Successor | New Common Stock
Class of Stock [Line Items]
Common stock, issued (in shares)	18,900,000	18,900,000
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Shares reserved for future distribution	400,000	400,000
Successor | Series A Warrants
Class of Stock [Line Items]
Number of shares to be issued	4,900,000	4,900,000
Shares issued	4,500,000
Exercise price of warrants (in usd per share)	$ 41.34	$ 41.34
Successor | Series B Warrants
Class of Stock [Line Items]
Number of shares to be issued	2,100,000	2,100,000
Shares issued	1,900,000
Exercise price of warrants (in usd per share)	$ 42.03	$ 42.03
Predecessor
Class of Stock [Line Items]
Common stock, issued (in shares)			635,584,000
Common stock, par value (in dollars per share)			$ 0.001
Shares authorized (in shares)			1,800,000,000
Shares held in treasury (in shares)			2,100,000
Common stock issued for debt (in shares)		84,400,000	92,800,000
Additional paid-in capital - stockholder receivable			$ (1,250)
Predecessor | 7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Shares converted			200,000
Predecessor | Common Stock and Preferred Stock
Class of Stock [Line Items]
Shares authorized, par value (usd per share)					$ 0.001
Predecessor | Senior Notes | Common Stock
Class of Stock [Line Items]
Common stock issued for debt (in shares)			28,000,000
Predecessor | Convertible Debt
Class of Stock [Line Items]
Debt conversion, original debt, amount		$ 232,100	$ 255,300
Predecessor | Convertible Debt | Common Stock
Class of Stock [Line Items]
Common stock issued for debt (in shares)		84,400,000	92,800,000
Predecessor | 7.5% Senior Notes Due 2021 And 8.125% Senior Notes Due 2022 | Senior Notes
Class of Stock [Line Items]
Debt conversion, original debt, amount			$ 50,000
Predecessor | Minimum | Common Stock
Class of Stock [Line Items]
Shares authorized (in shares)					800,000,000
Predecessor | Minimum | Preferred Stock
Class of Stock [Line Items]
Shares authorized (in shares)					50,000,000
Predecessor | Minimum | Common Stock and Preferred Stock
Class of Stock [Line Items]
Shares authorized (in shares)					850,000,000
Predecessor | Maximum | Common Stock
Class of Stock [Line Items]
Shares authorized (in shares)					1,800,000,000
Predecessor | Maximum | Preferred Stock
Class of Stock [Line Items]
Shares authorized (in shares)					50,000,000
Predecessor | Maximum | Common Stock and Preferred Stock
Class of Stock [Line Items]
Shares authorized (in shares)					1,850,000,000

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Equity - Preferred Stock Terms (Details) - $ / shares		12 Months Ended
	Oct. 01, 2016	Dec. 31, 2015
8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage		8.50%
Liquidation preference per share (usd per share)		$ 100.00
Annual dividend per share (usd per share)		$ 8.50
Conversion rate per share to common stock (shares)		12.4805
7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage		7.00%
Liquidation preference per share (usd per share)		$ 100.00
Annual dividend per share (usd per share)		$ 7.00
Conversion rate per share to common stock (shares)		12.8791
Predecessor
Class of Stock [Line Items]
Common Stock, Converted from Convertible Preferred Stock		3,000,000
Predecessor | 8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	8.50%	8.50%
Predecessor | 7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	7.00%	7.00%

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Equity - Preferred Stock Dividends (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands				9 Months Ended	12 Months Ended
	Oct. 01, 2016	Aug. 17, 2015	May 15, 2015	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage					8.50%
7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage					7.00%
Predecessor
Class of Stock [Line Items]
Dividends satisfied in shares of common stock				$ 0	$ 16,188	$ 0
Predecessor | 8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	8.50%				8.50%
Dividends paid in cash				0	$ 11,262	22,525
Dividends satisfied in shares of common stock				0	11,262	0
Accrued dividends at period end				0	8,447	8,447
Dividends in arrears				11,262	$ 0	0
Predecessor | 7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	7.00%				7.00%
Dividends paid in cash				0	$ 0	21,000
Dividends satisfied in shares of common stock				0	10,500	0
Accrued dividends at period end				0	13,125	2,625
Dividends in arrears				21,000	$ 10,500	0
Predecessor | 6.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage					6.00%
Dividends paid in cash				0	$ 0	12,000
Accrued dividends at period end				$ 0	$ 0	$ 0
Predecessor | Common Stock
Class of Stock [Line Items]
Convertible perpetual preferred stock dividends (in shares)					24,289
Predecessor | Common Stock | 8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Convertible perpetual preferred stock dividends (in shares)					18,600
Multiplier used in determining price of shares issued (percentage)					95.00%
Market value of common stock issued as dividends		$ 9,500
Common shares issued, value per preferred share (usd per share)		$ 3.58
Reduction to preferred stock dividends		$ 1,800
Predecessor | Common Stock | 7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Convertible perpetual preferred stock dividends (in shares)					5,700
Multiplier used in determining price of shares issued (percentage)					95.00%
Market value of common stock issued as dividends			$ 6,700
Common shares issued, value per preferred share (usd per share)			$ 2.23
Reduction to preferred stock dividends			$ 3,800

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Equity - Treasury Stock Activity (Details) - Predecessor - USD ($) shares in Thousands, $ in Thousands	9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Equity, Class of Treasury Stock [Line Items]
Value of shares withheld for taxes	$ 44	$ 2,428	$ 6,373
Value of shares retired	$ 0	$ 0	$ 0
Treasury Stock
Equity, Class of Treasury Stock [Line Items]
Number of shares withheld for taxes	1,122	1,872	1,034
Value of shares withheld for taxes	$ 44	$ 2,428	$ 6,373
Number of shares retired	1,122	1,872	1,034
Value of shares retired	$ 44	$ 2,428	$ 6,373

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Share-Based Compensation - Summary of Unvested Restricted Stock Awards (Details) - Restricted Stock - $ / shares shares in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Number of Shares
Unvested shares/units outstanding at beginning of period	0
Granted (in shares)	1,448
Vested (in shares)	(14)
Forfeited / Canceled (in shares)	(27)
Unvested shares/units outstanding at end of period	1,407	0
Weighted- Average Grant Date Fair Value (usd per share)
Unvested restricted shares outstanding at beginning of period (in usd per share)	$ 0.00
Granted (in usd per share)	24.32
Vested (in usd per share)	24.32
Forfeited / Canceled (in usd per share)	24.32
Unvested restricted shares outstanding at end of period (in usd per share)	$ 24.32	$ 0.00
Predecessor
Number of Shares
Unvested shares/units outstanding at beginning of period	0	5,626	8,556	7,643
Granted (in shares)		0	2,928	6,367
Vested (in shares)		(3,034)	(5,186)	(3,432)
Forfeited / Canceled (in shares)		(2,592)	(672)	(2,022)
Unvested shares/units outstanding at end of period		0	5,626	8,556
Weighted- Average Grant Date Fair Value (usd per share)
Unvested restricted shares outstanding at beginning of period (in usd per share)	$ 0.00	$ 4.85	$ 6.39	$ 6.92
Granted (in usd per share)		0.00	0.88	6.17
Vested (in usd per share)		5.34	4.95	7.04
Forfeited / Canceled (in usd per share)		4.31	6.38	6.60
Unvested restricted shares outstanding at end of period (in usd per share)		$ 0.00	$ 4.85	$ 6.39

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Share-Based Compensation - Narrative (Details) - USD ($) shares in Thousands, $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Oct. 31, 2016	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		1,448
Share-based compensation expense		$ 6.6
Share-based compensation, capitalized		0.3
Severance, compensation cost of accelerated shares		$ 4.3
Severance, number of accelerated shares		200
Unrecognized compensation cost related to unvested awards		$ 27.1
Period of recognition for unrecognized costs		2 years 9 months 18 days
Successor | 2016 Omnibus Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance			4,600
Successor | 2016 Omnibus Incentive Plan | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	1,400
Vesting period (in years)	3 years
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense			$ 11.2	$ 21.7	$ 22.6
Share-based compensation, capitalized			$ 1.7	$ 5.9	$ 6.0
Predecessor | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted			0	2,928	6,367
Vesting period (in years)			4 years
Severance, compensation cost of accelerated shares			$ 5.4
Severance, number of accelerated shares			1,300
Unrecognized compensation cost related to unvested awards			$ 5.9

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Incentive and Deferred Compensation Plans (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014	Jan. 31, 2016
Predecessor | Deferred Compensation Plans
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Retirement plan, employer matching contribution, percent of match			100.00%	100.00%	100.00%
Retirement plan, employer matching contribution, vesting period			4 years	4 years	4 years
Retirement plan, employer matching contribution, percent of employees' gross pay (up to)			10.00%	10.00%	10.00%
Retirement plan, cost recognized			$ 4.9	$ 7.9	$ 8.7
Percent of employee contributions vesting immediately			100.00%	100.00%	100.00%
Predecessor | Annual Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Accrued bonuses				$ 21.6
Predecessor | Minimum | Management Annual Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Incentive plans, payout percentages of target values				0.00%
Predecessor | Maximum | Management Annual Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Incentive plans, payout percentages of target values				200.00%
Predecessor | Performance Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Payments to employees		$ 17.8
Predecessor | Performance Incentive Plan | Minimum
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Incentive plans, payout percentages of target values						0.00%
Predecessor | Performance Incentive Plan | Maximum
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Incentive plans, payout percentages of target values						200.00%
Successor
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Deferred compensation plan assets to be distributed to participants	$ 7.5
Successor | Deferred Compensation Plans
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Retirement plan, employer matching contribution, percent of match	100.00%
Retirement plan, employer matching contribution, vesting period	4 years
Retirement plan, employer matching contribution, percent of employees' gross pay (up to)	10.00%
Retirement plan, cost recognized	$ 0.9
Percent of employee contributions vesting immediately	100.00%
Successor | Performance Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Payments to employees	$ 7.1
Accrued bonuses	$ 15.8

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Income Taxes - (Benefit) Provision for Income Taxes (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Current
Federal	$ 0
State	9
Current, total	9
Deferred
Federal	0
State	0
Deferred, total	0
Total provision (benefit)	9
Successor | Noncontrolling Interest
Deferred
Total provision (benefit)	0
Successor | Parent
Deferred
Total provision (benefit)	$ 9
Predecessor
Current
Federal		$ 0	$ 0	$ (1,160)
State		11	123	(1,133)
Current, total		11	123	(2,293)
Deferred
Federal		0	0	0
State		0	0	0
Deferred, total		0	0	0
Total provision (benefit)		11	123	(2,293)
Predecessor | Noncontrolling Interest
Deferred
Total provision (benefit)		0	90	283
Predecessor | Parent
Deferred
Total provision (benefit)		$ 11	$ 33	$ (2,576)

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Income Taxes - Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate to Company's Actual Income Tax Benefit (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Reconciliation Of Provision Of Income Taxes [Line Items]
Total provision (benefit)	$ 9
Successor | Parent
Reconciliation Of Provision Of Income Taxes [Line Items]
Computed at federal statutory rate	(116,891)
State taxes, net of federal benefit	(3,696)
Non-deductible expenses	144
Non-deductible debt costs	0
Stock-based compensation	306
Net effects of consolidating the non-controlling interests’ tax provisions	0
Discharge of debt and other reorganization related items	0
Change in valuation allowance	120,144
Other	2
Total provision (benefit)	$ 9
Predecessor
Reconciliation Of Provision Of Income Taxes [Line Items]
Total provision (benefit)		$ 11	$ 123	$ (2,293)
Predecessor | Parent
Reconciliation Of Provision Of Income Taxes [Line Items]
Computed at federal statutory rate		504,283	(1,512,325)	122,362
State taxes, net of federal benefit		10,512	(19,988)	4,145
Non-deductible expenses		462	816	1,895
Non-deductible debt costs		22,694	10,228	0
Stock-based compensation		5,884	6,700	1,467
Net effects of consolidating the non-controlling interests’ tax provisions		0	218,196	(34,614)
Discharge of debt and other reorganization related items		359,278	0	0
Change in valuation allowance		(903,102)	1,296,405	(96,769)
Other		0	1	(1,062)
Total provision (benefit)		$ 11	$ 33	$ (2,576)

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Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Deferred tax liabilities
Investments	$ 275,128
Derivative contracts	0
Long-term debt	0
Total deferred tax liabilities	275,128
Deferred tax assets
Property, plant and equipment	751,683
Derivative contracts	11,274
Allowance for doubtful accounts	1,487
Net operating loss carryforwards	527,079
Compensation and benefits	14,494
Alternative minimum tax credits and other carryforwards	43,770
Asset retirement obligations	40,399
CO2 under-delivery shortfall penalty	0
Other	4,663
Total deferred tax assets	1,394,849
Valuation allowance	(1,119,721)
Net deferred tax liability	$ 0
Predecessor
Deferred tax liabilities
Investments		$ 138,310
Derivative contracts		30,989
Long-term debt		10,017
Total deferred tax liabilities		179,316
Deferred tax assets
Property, plant and equipment		807,275
Derivative contracts		0
Allowance for doubtful accounts		18,702
Net operating loss carryforwards		1,190,799
Compensation and benefits		18,607
Alternative minimum tax credits and other carryforwards		44,302
Asset retirement obligations		38,314
CO2 under-delivery shortfall penalty		40,654
Other		4,305
Total deferred tax assets		2,162,958
Valuation allowance		(1,983,642)	$ (649,600)
Net deferred tax liability		$ 0

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Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015
Successor
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefit at January 1	$ 81
Changes to unrecognized tax benefits related to a prior year	3
Unrecognized tax benefit at December 31	84	$ 81
Predecessor
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefit at January 1	$ 81	81	$ 77
Changes to unrecognized tax benefits related to a prior year		0	4
Unrecognized tax benefit at December 31		$ 81	$ 81

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Income Taxes - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Operating Loss Carryforwards [Line Items]
Valuation allowance	$ 1,119,721
Unrecognized tax benefits	84	$ 81
Successor | Alternative Minimum Tax Credit Carryforward
Operating Loss Carryforwards [Line Items]
Alternative minimum tax credits, not subject to expiration	$ 9,300
Successor | Earliest Tax Year
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards expiration year	2028
Successor | Latest Tax Year
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards expiration year	2036
Successor | Domestic Tax Authority
Operating Loss Carryforwards [Line Items]
Federal net operating loss carryovers	$ 1,300,000
Predecessor
Operating Loss Carryforwards [Line Items]
Valuation allowance			$ 1,983,642	$ 649,600
Unrecognized tax benefits		81	$ 81	$ 77
Reorganization Adjustments | Domestic Tax Authority
Operating Loss Carryforwards [Line Items]
Federal net operating loss carryovers		$ 3,700,000

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Income Taxes - Periods Open to Tax Examination (Details) - Successor	3 Months Ended
	Dec. 31, 2016
Domestic Tax Authority | Earliest Tax Year
Income Tax Contingency [Line Items]
Open tax year	2013
Net Operating Loss And Other Carryforwards | Earliest Tax Year
Income Tax Contingency [Line Items]
Open tax year	2005
Net Operating Loss And Other Carryforwards | Latest Tax Year
Income Tax Contingency [Line Items]
Open tax year	2012
Minimum
Income Tax Contingency [Line Items]
Number of tax years open for state tax audit (in years)	3 years
Maximum
Income Tax Contingency [Line Items]
Number of tax years open for state tax audit (in years)	5 years

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(Loss) Earnings per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		3 Months Ended								9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 01, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Effect of dilutive securities
net (Loss) Income, Warrants											$ 0
Successor
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net (Loss) Income, Basic		$ (333,982)
Weighted Average Shares, basic		18,967
(Loss) Earnings Per Share, Basic (in dollars per share)		$ (17.61)
Effect of dilutive securities
Net (Loss) Income, Restricted stock		$ 0
Weighted Average Shares, Restricted stock		0
Weighted Average Shares, Warrants		0
Weighted Average Shares, Convertible notes (in shares)		0
Net (Loss) Income, Diluted		$ (333,982)
Weighted Average Shares, Diluted (in shares)		18,967
(Loss) Earnings Per Share, Diluted (in dollars per share)		$ (17.61)
Predecessor
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net (Loss) Income, Basic	$ 2,674,271		$ (404,337)	$ (521,351)	$ (324,107)	$ (664,579)	$ (649,526)	$ (1,375,556)	$ (1,045,834)	$ 1,424,476		$ (3,735,495)	$ 203,260
Weighted Average Shares, basic										708,928		521,936	479,644
(Loss) Earnings Per Share, Basic (in dollars per share)	$ 3.72		$ (0.56)	$ (0.73)	$ (0.47)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 2.01		$ (7.16)	$ 0.42
Effect of dilutive securities
Net (Loss) Income, Restricted stock										$ 0		$ 0	$ 0
Weighted Average Shares, Restricted stock										0		0	2,181
Net (Loss) Income, Convertible notes											$ 0	$ 0
Weighted Average Shares, Convertible notes (in shares)												0
Net (Loss) Income, Convertible preferred stock												$ 0	$ 6,500
Weighted Average Shares, Convertible preferred stock												0	17,918
Net (Loss) Income, Diluted										$ 1,424,476		$ (3,735,495)	$ 209,760
Weighted Average Shares, Diluted (in shares)										708,928		521,936	499,743
(Loss) Earnings Per Share, Diluted (in dollars per share)	$ 3.72		$ (0.56)	$ (0.73)	$ (0.47)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 2.01		$ (7.16)	$ 0.42

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(Loss) Earnings per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share (Additional Information) (Details) - shares		3 Months Ended	9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
8.5% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage					8.50%
7.0% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage					7.00%
Successor | Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share		0	0
Successor | New Convertible Notes
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share		14,600,000
Successor | 8.5% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage				0.00%
Successor | 7.0% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage				0.00%
Predecessor | Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share					0
Predecessor | Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share					71,200,000	71,700,000
Predecessor | Convertible Debt Securities
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share					48,500,000
Predecessor | Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share				0
Predecessor | 8.125% Convertible Senior Notes due 2022
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Long-term debt, fixed interest rate					8.125%
Predecessor | 7.5% Convertible Senior Notes due 2023
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Long-term debt, fixed interest rate					7.50%
Predecessor | 8.5% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage	8.50%				8.50%
Predecessor | 6.0% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage					6.00%
Predecessor | 7.0% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage	7.00%				7.00%

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Subsequent Events - Narrative (Details) shares in Millions			1 Months Ended
	Feb. 10, 2017 USD ($) a well shares	Oct. 01, 2016 USD ($)	Feb. 09, 2017 USD ($) shares
New First Lien Exit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Principal amount of commitments		$ 425,000,000
Cash collateral account		50,000,000
Liquidity requirement		$ 20,000,000
LIBOR | New First Lien Exit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Basis spread on variable rate		4.75%
Variable rate floor		1.00%
Subsequent Event
Subsequent Event [Line Items]
Number of acres acquired | a	13,000
Cash paid for acres	$ 47,800,000
Number of wells acquired | well	4
Subsequent Event | Amended New Credit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Principal amount of commitments	$ 600,000,000
Borrowing base	425,000,000
Subsequent Event | New Convertible Notes | Convertible Debt
Subsequent Event [Line Items]
Debt conversion, original debt, amount	$ 263,700,000		$ 5,100,000
Common stock issued for debt (in shares) | shares	14.1		0.3
Subsequent Event | LIBOR | Amended New Credit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Variable rate floor	0.00%
Subsequent Event | Minimum | LIBOR | Amended New Credit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Basis spread on variable rate	3.00%
Subsequent Event | Minimum | Base Rate | Amended New Credit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Basis spread on variable rate	2.00%
Subsequent Event | Maximum | LIBOR | Amended New Credit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Basis spread on variable rate	4.00%
Subsequent Event | Maximum | Base Rate | Amended New Credit Facility | Revolving Credit Facility
Subsequent Event [Line Items]
Basis spread on variable rate	3.00%

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Oil and natural gas properties
Proved	$ 840,201
Unproved	74,937
Total oil and natural gas properties	915,138
Less: accumulated depreciation, depletion and impairment	(353,030)
Net oil and natural gas properties capitalized costs	$ 562,108
Predecessor
Oil and natural gas properties
Proved		$ 12,529,681	$ 11,707,147
Unproved		363,149	290,596
Total oil and natural gas properties		12,892,830	11,997,743
Less: accumulated depreciation, depletion and impairment		(11,149,888)	(6,359,149)
Net oil and natural gas properties capitalized costs		$ 1,742,942	$ 5,638,594

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Acquisitions of properties
Proved	$ 5,142
Unproved	5,491
Exploration	0
Development	27,429
Total cost incurred	$ 38,062
Predecessor
Acquisitions of properties
Proved		$ 3,897	$ 35,376	$ 73,370
Unproved		1,899	210,065	123,649
Exploration		1,234	29,297	41,070
Development		149,924	571,562	1,288,395
Total cost incurred		$ 156,954	846,300	1,526,484
Predecessor | Seismic Costs
Acquisitions of properties
Exploration			$ 7,100	$ 10,800

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Results of Operations from Oil and Natural Gas Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues	$ 98,307
Expenses
Production costs	27,640
Depreciation and depletion	33,971
Accretion of asset retirement obligations	2,090
Impairment	319,087
Total expenses	382,788
(Loss) income before income taxes	(284,481)
Income tax expense (benefit)	8
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$ (284,489)
Predecessor
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Revenues		$ 279,971	$ 707,434	$ 1,420,879
Expenses
Production costs		135,715	324,141	377,819
Depreciation and depletion		86,613	319,913	434,295
Accretion of asset retirement obligations		4,365	4,477	9,092
Impairment		657,392	4,473,787	164,779
Total expenses		884,085	5,122,318	985,985
(Loss) income before income taxes		(604,114)	(4,414,884)	434,894
Income tax expense (benefit)		(5)	126	(2,852)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)		$ (604,109)	$ (4,415,010)	$ 437,746

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Summary of Changes in Estimated Oil and Natural Gas Reserves (Unaudited) (Details) Mcf in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016 MBbls Mcf	Oct. 01, 2016 MBbls Mcf	Dec. 31, 2015 MBbls Mcf	Dec. 31, 2014 MBbls Mcf	Dec. 31, 2013 MBbls Mcf
Oil | Non-controlling Interest
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance		7,004	11,027
Proved developed and undeveloped reserves, ending balance			7,004	11,027
NGL | Non-controlling Interest
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance		3,694	4,761
Proved developed and undeveloped reserves, ending balance			3,694	4,761
Natural Gas | Non-controlling Interest
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance | Mcf		50,508	70,833
Proved developed and undeveloped reserves, ending balance | Mcf			50,508	70,833
Predecessor | Oil
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance	27,252	77,911	126,031	142,641
Adoption of ASU 2015-02		(6,971)
Revisions of previous estimates		(39,973)	(70,708)	(18,687)
Acquisitions of new reserves			22,447	1,009
Extensions and discoveries		987	9,741	37,603
Sales of reserves in place		(387)		(25,659)
Production		(4,315)	(9,600)	(10,876)
Proved developed and undeveloped reserves, ending balance		27,252	77,911	126,031
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)		24,541	48,639	79,022	83,893
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)		2,711	29,272	47,009	58,748
Predecessor | NGL
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance	33,019	61,075	91,786	59,052
Adoption of ASU 2015-02		(3,695)
Revisions of previous estimates		(21,475)	(37,384)	11,103
Acquisitions of new reserves			2,460	441
Extensions and discoveries		472	9,257	27,500
Sales of reserves in place		0		(2,516)
Production		(3,358)	(5,044)	(3,794)
Proved developed and undeveloped reserves, ending balance		33,019	61,075	91,786
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)		30,238	51,089	56,823	35,807
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)		2,781	9,986	34,963	23,245
Predecessor | Natural Gas
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance | Mcf	466,328	1,113,840	1,788,233	1,390,429
Adoption of ASU 2015-02 | Mcf		(50,508)
Revisions of previous estimates | Mcf		(415,568)	(759,106)	167,589
Acquisitions of new reserves | Mcf			15,952	12,527
Extensions and discoveries | Mcf		7,955	160,865	467,185
Sales of reserves in place | Mcf		(145,267)		(163,800)
Production | Mcf		(44,124)	(92,104)	(85,697)
Proved developed and undeveloped reserves, ending balance | Mcf		466,328	1,113,840	1,788,233
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf		428,050	964,617	1,203,447	951,609
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf		38,278	149,223	584,786	438,820
Successor | Oil
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Revisions of previous estimates	23,978
Extensions and discoveries	2,868
Production	(1,214)
Proved developed and undeveloped reserves, ending balance	52,884
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	25,911
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	26,973
Successor | NGL
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Revisions of previous estimates	1,139
Extensions and discoveries	448
Production	(999)
Proved developed and undeveloped reserves, ending balance	33,607
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	29,290
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	4,317
Successor | Natural Gas
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Revisions of previous estimates | Mcf	915
Extensions and discoveries | Mcf	10,309
Production | Mcf	(12,770)
Proved developed and undeveloped reserves, ending balance | Mcf	464,782
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf	393,028
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf	71,754

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Calculation of Weighted Average Per Unit Prices (Unaudited) (Details)	3 Months Ended	12 Months Ended
	Dec. 31, 2016 $ / Mcf $ / bbl	Dec. 31, 2015 $ / Mcf $ / bbl	Dec. 31, 2014 $ / Mcf $ / bbl
Successor | Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas)	38.59
Successor | NGL
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas)	10.99
Successor | Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | $ / Mcf	1.56
Predecessor | Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas)		45.29	91.65
Predecessor | NGL
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas)		12.68	32.79
Predecessor | Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | $ / Mcf		1.87	3.61

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Future Cash Flows (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Successor
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows from production	$ 3,136,762
Future production costs	(1,454,798)
Future development costs	(665,516)
Future income tax expenses	(142)
Undiscounted future net cash flows	1,016,306
10% annual discount	(577,942)
Standardized measure of discounted future net cash flows	$ 438,364	$ 392,604
Predecessor
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future cash inflows from production			$ 6,387,944	$ 21,022,320
Future production costs			(2,731,542)	(6,499,366)
Future development costs			(838,945)	(1,810,201)
Future income tax expenses			(901)	(3,223,740)
Undiscounted future net cash flows			2,816,556	9,489,013
10% annual discount			(1,501,994)	(5,401,261)
Standardized measure of discounted future net cash flows		$ 392,604	1,314,562	4,087,752	$ 4,017,611
Predecessor | Non-controlling Interest
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows			$ 224,600	$ 643,300

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Successor
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Present value, beginning balance	$ 392,604
Changes during the year
Adoption of ASU 2015-02	0
Revenues less production and other costs	(70,668)
Net changes in prices, production and other costs	35,684
Development costs incurred	7,941
Net changes in future development costs	(291,232)
Extensions and discoveries	14,986
Revisions of previous quantity estimates	308,374
Accretion of discount	9,375
Net change in income taxes	0
Purchases of reserves in-place	0
Sales of reserves in-place	0
Timing differences and other	31,300
Net change for the year	45,760
Present value, ending balance	438,364	$ 392,604
Predecessor
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Present value, beginning balance	$ 392,604	1,314,562	$ 4,087,752	$ 4,017,611
Changes during the year
Adoption of ASU 2015-02		(224,965)	0	0
Revenues less production and other costs		(144,256)	(383,293)	(1,043,060)
Net changes in prices, production and other costs		(394,173)	(3,813,465)	331,694
Development costs incurred		69,080	217,596	364,262
Net changes in future development costs		436,041	273,437	(341,183)
Extensions and discoveries		12,449	230,055	1,785,963
Revisions of previous quantity estimates		(728,254)	(1,354,778)	(77,688)
Accretion of discount		91,337	512,483	477,458
Net change in income taxes		402	1,426,333	(256,371)
Purchases of reserves in-place		0	18,429	50,958
Sales of reserves in-place		(13,314)	0	(1,058,330)
Timing differences and other		(26,305)	100,013	(163,562)
Net change for the year		(921,958)	(2,773,190)	70,141
Present value, ending balance		392,604	1,314,562	4,087,752
Noncontrolling Interest | Predecessor
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Present value, beginning balance		$ 224,600	643,300
Changes during the year
Present value, ending balance			$ 224,600	$ 643,300

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Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Narrative (Details) Mcf in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016 MBbls Mcf	Oct. 01, 2016 MBbls Mcf	Dec. 31, 2016 MMBoe	Dec. 31, 2015 MMBoe MBbls Mcf	Dec. 31, 2014 MMBoe MBbls Mcf
Reserve Quantities [Line Items]
Percentage of proved reserves estimated by the Company	6.00%		6.00%
Total downward revision | MMBoe			(105,400)
Downward revision due to change in estimates | MMBoe			94,700
Downward revision due to change in previous estimates due to pricing | MMBoe			12,100
Decrease in reserves due to sale (MMBoe) | MMBoe			24,600
Decrease in reserves due to changes in accounting | MMBoe			19,100
Upward revision of estimates due to extensions | MMBoe			7,800
Natural Gas and LNG
Reserve Quantities [Line Items]
Percent share of downward revision			85.00%
Oil
Reserve Quantities [Line Items]
Percent share of downward revision			15.00%
Successor | Oil
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)	2,868
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	23,978
Successor | Natural Gas
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf	10,309
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf	915
Successor | NGL
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)	448
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	1,139
Predecessor
Reserve Quantities [Line Items]
Expected period without drilling activity					5 years
Acquisitions of new reserves (MMBoe) | MMBoe					3.5
Predecessor | Oil
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)		987		9,741	37,603
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)		(39,973)		(70,708)	(18,687)
Predecessor | Natural Gas
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf		7,955		160,865	467,185
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf		(415,568)		(759,106)	167,589
Predecessor | NGL
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)		472		9,257	27,500
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)		(21,475)		(37,384)	11,103
Predecessor | Gulf Properties
Reserve Quantities [Line Items]
Decrease in reserves due to sale (MMBoe) | MMBoe					55.5
Predecessor | Lower Commodity Price | Oil
Reserve Quantities [Line Items]
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)				(54,000)
Predecessor | Lower Commodity Price | Natural Gas
Reserve Quantities [Line Items]
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf				(687,000)
Predecessor | Lower Commodity Price | NGL
Reserve Quantities [Line Items]
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)				(36,000)
Predecessor | North Park Basin, Jackson County, Colorado [Member]
Reserve Quantities [Line Items]
Acquisitions of new reserves (MMBoe) | MMBoe				27.6
Predecessor | Mid-Continent and Permian Basin | Oil
Reserve Quantities [Line Items]
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)					(2,000)
Predecessor | Mid-Continent | Oil
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)				9,700
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)				(16,000)	(8,000)
Predecessor | Mid-Continent | Natural Gas
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf				160,900
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf				(74,000)
Predecessor | Mid-Continent | NGL
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)				9,300
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)				(1,000)
Predecessor | Permian Properties | Oil
Reserve Quantities [Line Items]
Positive (negative) Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)					(9,000)

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Quarterly Financial Results (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended								9 Months Ended	12 Months Ended
	Oct. 01, 2016	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Oct. 01, 2016	Dec. 31, 2015	Dec. 31, 2014
Predecessor
Quarterly Financial Information [Line Items]
Total revenues	$ 0		$ 104,056	$ 99,421	$ 90,332	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 293,809	$ 768,709	$ 1,558,758
Loss from operations	0		(357,338)	(275,310)	(273,555)	(959,406)	(1,059,733)	(1,535,083)	(1,088,456)	(906,203)	(4,642,678)	590,224
Net (loss) income	2,674,271		(404,337)	(515,911)	(313,226)	(783,961)	(796,485)	(1,588,731)	(1,151,874)	1,440,797	(4,321,051)	351,898
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$ 2,674,271		$ (404,337)	$ (521,351)	$ (324,107)	$ (664,579)	$ (649,526)	$ (1,375,556)	$ (1,045,834)	$ 1,424,476	$ (3,735,495)	$ 203,260
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
Basic (in dollars per share)	$ 3.72		$ (0.56)	$ (0.73)	$ (0.47)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 2.01	$ (7.16)	$ 0.42
Diluted (in dollars per share)	$ 3.72		$ (0.56)	$ (0.73)	$ (0.47)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 2.01	$ (7.16)	$ 0.42
Impairment			$ 354,500	$ 253,600	$ 110,100	$ 886,800	$ 1,100,000	$ 1,500,000	$ 1,100,000	$ 718,194	$ 4,534,689	$ 192,768
Loss on settlement of contract					89,100					90,184	50,976	0
Loss (gain) on derivative contracts						$ (14,000)	$ (42,200)	$ 33,000	$ (49,800)	4,823	(73,061)	(334,011)
Gain on extinguishment of debt					$ 41,300					$ 41,179	$ 641,131	$ 0
Gain (loss) on reorganization items	$ 2,700,000		$ (42,800)	$ (200,900)
Successor
Quarterly Financial Information [Line Items]
Total revenues		$ 98,456
Loss from operations		(336,345)
Net (loss) income		(333,982)
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders		$ (333,982)
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
Basic (in dollars per share)		$ (17.61)
Diluted (in dollars per share)		$ (17.61)
Impairment		$ 319,087
Loss on settlement of contract		0
Loss (gain) on derivative contracts		25,652
Gain on extinguishment of debt		$ 0

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Label	Element	Value
Predecessor [Member]
Additional Paid in Capital Substantial Premium Component of Convertible Debt	sd_AdditionalPaidinCapitalSubstantialPremiumComponentofConvertibleDebt	$ 163,879,000
Stock Issued During Period, Value, Warrants	sd_StockIssuedDuringPeriodValueWarrants	88,382,000
Stock Issued During Period, Value, New Issues	us-gaap_StockIssuedDuringPeriodValueNewIssues	575,163,000
Retained Earnings [Member] | Predecessor [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	(5,311,140,000)
Treasury Stock [Member] | Predecessor [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	(5,218,000)
Additional Paid-in Capital [Member] | Predecessor [Member]
Additional Paid in Capital Substantial Premium Component of Convertible Debt	sd_AdditionalPaidinCapitalSubstantialPremiumComponentofConvertibleDebt	163,879,000
Stock Issued During Period, Value, New Issues	us-gaap_StockIssuedDuringPeriodValueNewIssues	575,144,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	$ 5,314,405,000
Warrant [Member] | Predecessor [Member]
Stock Issued During Period, Shares, Warrants	sd_StockIssuedDuringPeriodSharesWarrants	6,442,000
Stock Issued During Period, Value, Warrants	sd_StockIssuedDuringPeriodValueWarrants	$ 88,382,000
Preferred Stock [Member] | Predecessor [Member]
Preferred Stock, Shares Outstanding	us-gaap_PreferredStockSharesOutstanding	5,247,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	$ 6,000
Noncontrolling Interest [Member] | Predecessor [Member]
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	$ (21,000)
Common Stock [Member] | Predecessor [Member]
Common Stock, Shares, Outstanding	us-gaap_CommonStockSharesOutstanding	718,500,000
Stock Issued During Period, Value, New Issues	us-gaap_StockIssuedDuringPeriodValueNewIssues	$ 19,000
Stock Issued During Period, Shares, New Issues	us-gaap_StockIssuedDuringPeriodSharesNewIssues	18,932,000
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest	$ 718,000