SD 10-K Fiscal year ended Dec. 31, 2017

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•	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 our growth strategy by drilling wells as planned;

•	the amount, nature and timing of capital expenditures, including future development costs, required to develop our undeveloped areas;

•	concentration of operations in the Mid-Continent region of the United States;

•	risks associated with shareholder activism;

•	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.

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(1)	Average daily net production for the month of December 2017 .

(2)	Estimated net proved reserves as of December 31, 2017 divided by production for the month of December 2017 , annualized.

(3)	Capital expenditures for the year ended December 31, 2017 , on an accrual basis.

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•	the quality and quantity of available data and the engineering and geological interpretation of that data;

•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•	the accuracy of economic assumptions; and

•	the judgment of the personnel preparing the estimates.

•	the Corporate Reserves 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.

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•	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.

•	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.

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•	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;

•	practicing consultant in petroleum engineering since 2013 and over 14 years of prior industry experience;

•	licensed professional engineers in the state of Texas; and

•	Bachelor of Science Degree in Chemical Engineering

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(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, 2017 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.

(a)	Index prices are based on average West Texas Intermediate (“WTI”) Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.

(b)	Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, and regional price differentials.

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

(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, 2017 and 2016, the present value of future income tax discounted at 10% was insignificant due to an excess of tax basis in oil and natural gas properties over projected undiscounted future cash flows from our proved reserves.

(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, 2017 , 2016 and 2015 . 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:

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

(2)	Excludes production and ad valorem taxes.

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

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(1)	Pending paying well determination.

(2)	Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.

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•	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.

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(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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•	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.

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•	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 or midstream facilities or delays in construction of gathering or midstream facilities;

•	lack of available capacity on interconnecting transmission pipelines;

•	lack of adequate electrical infrastructure and water disposal capacity;

•	unexpected operational events and drilling conditions;

•	pipe or cement failures and casing collapses;

•	pressures, fires, blowouts and explosions;

•	lost or damaged drilling and service tools;

•	loss of drilling fluid circulation;

•	uncontrollable flows of oil, natural gas, brine, water or drilling fluids;

•	natural disasters;

•	environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•	high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing;

•	compliance with environmental and other governmental requirements;

•	adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes;

•	oil and natural gas property title problems; and

•	market and midstream limitations for oil, natural gas and NGLs.

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•	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;

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•	our ability to acquire, locate and produce new reserves; and

•	our capital and operating costs.

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•	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.

•	evacuation of personnel and curtailment of operations;

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

•	inability to deliver materials to worksites; and

•	damage to, or shutting in of, pipelines and other transportation facilities.

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•	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.

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

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(1)	Includes shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards.

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(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, 2017 and December 31, 2013.

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(1)

Reflects the reclassification of certain debt issuance costs from other assets to long-term debt of $69.1 million, $47.4 million and $54.5 million for the years ended December 31, 2015, 2014 and 2013, 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 of the classification of debt issuance costs.

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•	Overview;

•	Consolidated Results of Operations;

•	Liquidity and Capital Resources;

•	Valuation Allowance; and

•	Critical Accounting Policies and Estimates.

•	Total production for 2017 was comprised of approximately 27.9% oil, 49.5% natural gas and 22.6% NGLs compared to 28.5% oil, 49.0% natural gas and 22.5% NGLs in 2016 .

•	Increased the total rigs drilling to four at December 31, 2017 from one at December 31, 2016.

•	Drilled 17 wells in the Mid-Continent and 6 wells in the North Park Basin in 2017 compared to drilling 16 wells in the Mid-Continent and 10 wells in the North Park Basin in 2016, respectively.

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In the third quarter of 2017, we entered into a $200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of our undeveloped leasehold acreage within the NW STACK. See “Note 5 - Recent Transactions” to the accompanying unaudited condensed consolidated financial statements for additional discussion of the drilling participation agreement.

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•

In November 2017, we announced our entry into a definitive merger agreement with Bonanza Creek Energy, Inc. (“Bonanza Creek”), whereby we would acquire all of the outstanding shares of common stock of Bonanza Creek in a cash and stock transaction valued at $36.00 per share. In December 2017, after consultation with our largest shareholders, we announced the mutual termination of this agreement. We incurred approximately $8.2 million in costs related to this terminated transaction through December 31, 2017.

•

On February 6, 2018, we received an unsolicited proposal from Midstates Petroleum Company, Inc. (“Midstates”) to combine SandRidge and Midstates in an all stock merger transaction. On February 7, 2018, we announced that our board of directors, in consultation with independent financial and legal advisers, will carefully review and evaluate Midstates’ proposal, taking into account our current strategic plan and standalone prospects.

•

On February 8, 2018, we announced the departure of James Bennett, President and CEO, effective immediately, and Julian Bott, Chief Financial Officer, effective at the close of business on the date of filing this 2017 Annual Report with the SEC. We also announced the appointment of independent board member, Bill Griffin, as Interim President and Chief Executive Officer, the appointment of Chief Accounting Officer, Michael Johnson, as Interim Chief Financial Officer and the appointment of Sylvia K. Barnes as an independent director.

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(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.

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

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

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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.

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(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.

(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)

Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2017. Certain of these estimates and assumptions are inherently unpredictable and will differ from actual results given the uncertainty regarding the timing of such expenditures. As a result, we do not expect to incur all of the estimated costs for the current asset retirement obligation shown above in the next year, and have budgeted $5.0 million for actual expected plugging and abandonment costs in 2018.

(4)

Includes the remaining obligation of $5.1 million 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. This plan was terminated and contributions were fully distributed to participants in January 2018.

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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:

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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 “First Lien Exit Facility”). Refer to Note 12 for additional information.

•	Cash Collateral Account. The Company deposited $ 50.0 million of cash in an account controlled by the administrative agent to the First Lien Exit Facility (the “Cash Collateral Account”). This deposit was released to the Company in February 2017 in conjunction with the refinancing of the First Lien Exit Facility.

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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 “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 “Convertible Notes”), which mandatorily converted into 14.1 million shares of Common Stock upon the refinancing of the First Lien Exit Facility in February 2017. Refer to Note 12 and Note 16 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 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 12 and Note 16 for additional information.

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Building Note . The Building Note with a principal amount of $ 35.0 million ( $ 36.6 million fair value on the Emergence Date), was issued and purchased on the Emergence Date for $ 26.8 million in cash, net of certain fees and expenses, by certain holders of the Senior Unsecured Notes. Proceeds received from the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan. Refer to Note 12 for additional information.

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•	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 16 for additional information.

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 stoc

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

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.

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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

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	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 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	)

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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 Building Note, $ 281.8 million of the Convertible Notes, and the $ 415.0 million drawn on the 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.

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

____________________

(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 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 Convertible Notes of $ 445.7 million and the principal value of the 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 7 .

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 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.

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Reorganization Items

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

Unamortized long-term debt		$	3,546,847
Litigation claims		( 20,478		)
Rejections and cures of executory contracts		( 16,038		)
Ad valorem and franchise taxes		( 3,494		)
Legal and professional fees and expenses		( 44,920		)
Write off of director and officer insurance policy		( 7,533		)
Gain on accounts payable settlements		84,228
Loss on mortgage		( 8,153		)
Gain on preferred stock dividends		37,893
Fresh start valuation adjustments		( 28,549		)
Fair value of equity issued		( 827,424		)
Principal value of Convertible Notes issued		( 281,780		)
Gain on reorganization items, net		$	2,430,599

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 North Park Basin regions of the United States. The Company’s North Park Basin properties were acquired during the fourth quarter of 2015.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries. During the year ended December 31, 2015, the Company fully consolidated the activities of each the SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Mississippian Trust II (the “Mississippian Trust II”) and SandRidge Permian Trust (the “Permian Trust”) (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) as variable interest entities for which the Company was the primary beneficiary. 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 years ended December 31, 2017 , and 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; the carrying value of unevaluated oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

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Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.

Restricted Cash. The Company maintains restricted escrow funds as required by certain contractual arrangements in accordance with the Plan.

Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the 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 collectibility 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 8 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 7 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 7 .

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 13 for further discussion of the Company’s derivatives.

Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Successor Company capitalized internal costs of $ 14.8 million and $ 4.0 million during the year ended December 31, 2017 and the Successor 2016 Period, respectively, and the Predecessor Company capitalized internal costs of $ 22.7 million and $ 45.1 million to the full cost pool during the Predecessor 2016 Period and the year ended December 31, 2015 , 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

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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 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 10 for further discussion of impairments.

Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During the year ended December 31, 2017 and the Successor 2016 Period, the Company did not capitalize any interest costs. During the Predecessor 2016 Period and the year ended December 31, 2015 , the Company capitalized interest of approximately $ 2.2 million and $ 10.8 million , respectively, on unproved properties that

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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 in 2015 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 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 are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 14 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 $ 29.1 million and $ 7.4 million of transportation costs as a reduction from revenues in the year ended December 31, 2017 and the Successor 2016 Period, respectively, versus the presentation of $ 26.2 million and $ 45.3 million , respectively, of these costs as production expenses in the Predecessor 2016 Period and the year ended December 31, 2015, respectively. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax 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 more or less than 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 $ 1.6 million and $ 1.7 million at December 31, 2017 and 2016 , respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

During the year ended December 31, 2015, 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 year ended December 31, 2015.

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 year ended December 31, 2015.

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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, during the Successor 2016 Period, the Company assumed the conversion of the Convertible Notes to common stock and determined if it was more dilutive than including the expense associated with the Convertible Notes in the computation of income available to common stockholders during the period the Convertible Notes were outstanding. 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 20 for the Company’s earnings per share calculation.

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Environmental liabilities related to future costs are recorded on an undiscounted basis when assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 15 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 credit facility constitutes a default under its commodity derivative contracts with counterparties that are lenders under the credit facility. The Company does not require collateral or other security from counterparties to support commodity derivative instruments. The Company has master netting agreements with all of its commodity derivative counterparties, which allow the Company to net its commodity derivative assets and liabilities for like commodities and derivative instruments with the same counterparty. As a result of the netting provisions, the Company’s maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against amounts owed, if any, to such counterparty under the Company’s credit facility.

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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
December 31, 2017 - Successor
Targa Pipeline Mid-Continent West OK LLC	$	144,583			40.5	%
Plains Marketing, L.P.	$	117,927			33.0	%
Period from October 2, 2016 through December 31, 2016 - Successor
Targa Pipeline Mid-Continent West OK LLC	$	35,845			36.4	%
Plains Marketing, L.P.	$	32,022			32.5	%
Period from January 1, 2016 through October 1, 2016 - Predecessor
Plains Marketing, L.P.	$	110,370			37.6	%
Targa Pipeline Mid-Continent West OK LLC	$	108,238			36.8	%
December 31, 2015 - Predecessor
Plains Marketing, L.P.	$	318,018			41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649			30.1	%

Recent Accounting Pronouncements. The Financial Accounting Standards Board (“FASB”) issued Accounting Standards

Update (“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 adopted the ASU

on April 1, 2017. The guidance had no impact on the consolidated financial statements and related disclosures.

The FASB Issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which

provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets

or as a business. The ASU is effective for the Company on January 1, 2018, and amendments should be applied prospectively on and after January 1, 2018. Early application is permitted for transactions for which the acquisition date occurs before the issuance date or effective date of the amendments, only when the transaction has not been reported in financial statements that have been issued or made available for issuance and for transactions in which a subsidiary is deconsolidated or a group of assets is derecognized that occur before the issuance date or effective date of the amendments, only when the transaction has not been reported in the financial statements that have been issued or made available for issuance. The Company applied this ASU for transactions effective after April 1, 2017 meeting the early application provisions above. The guidance had no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

The FASB issued ASU 2017-09, “Compensation - Stock Compensation (Topic 718): Scope of Modification Accounting,” which provides guidance on determining which changes to the terms and conditions of share-based payment awards require an entity to apply modification accounting. The amendments in this ASU are effective for the Company on January 1, 2018, with early adoption permitted in any interim period. The ASU should be applied prospectively to an award modified on or after the adoption date. The Company early adopted this ASU on July 1, 2017. The guidance had no impact on the consolidated financial statements and related disclosures.

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The FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” which outlines a single comprehensive model for entities to use in accounting for revenue arising 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 adopted Topic 606 on January 1, 2018, using the modified retrospective transition method.

Subsequent to the issuance of ASU 2014-09, the FASB issued various clarifications and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. Under this guidance, an entity generally shall record revenue on a gross basis if it controls a specified good or service before transferring it to a customer, whereas an entity shall record revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Significant judgment may be required in some circumstances to determine whether gross or net presentation is appropriate.

The Company has reviewed its contracts with customers and determined that this ASU will have no material impact on its balance sheet or related consolidated statement of earnings, stockholders’ equity or cash flows; however, the Company’s quarterly disclosures will expand in 2018 upon adoption of this ASU. The Company has implemented a process to gather and provide the quarterly disclosures required by the ASU.

The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory” which removes the prohibition in Accounting Standards Codification (“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 adopted the ASU on January 1, 2018. There was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets

(Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial

Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarify that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company may elect to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company elected to evaluate only contracts that are not completed contracts. As there were no not completed contracts at January 1, 2018, there was no impact to the Company’s consolidated financial statements and related disclosures upon adoption.

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases to explore for or use minerals, oil and natural gas are not impacted by this guidance. In January 2018, the FASB issued ASU 2018-01, “Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842.” This ASU permits an entity to continue to apply its current accounting policy for land easements that existed before the effective date of Topic 842. Once an entity adopts Topic 842, it would apply that Topic prospectively to all new (or modified) land easements to determine whether the arrangement contains a lease. Topic 842 requires adoption by application of a modified retrospective transition approach and is effective for the Company on January 1, 2019. Early adoption is permitted.

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

In the third quarter of 2017, the Company entered into a $ 200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of its undeveloped leasehold acreage within the Meramec formation in Major and Woodward Counties in Oklahoma (the “NW STACK”). Under this agreement, the Counterparty is paying 90 % of the net exploration and development costs, up to $ 100.0 million in the first tranche, in exchange for an initial 80 % net working interest in each new well, subject to certain reversionary hurdles, as shown in the table below. As a result, the Company is receiving a 20 % net working interest after funding 10 % of the exploration and development costs related to the subject wells. This will allow the Company to spend minimal additional capital while accelerating the delineation of its position in the NW STACK, realizing further efficiencies and holding additional acreage by production, potentially adding reserves. The Company operates all of the wells developed under this agreement and will retain sole discretion as to the number, location and schedule of wells drilled. The Counterparty will also have the option to fund a second $ 100.0 million tranche, subject to mutual agreement.

Development Costs and Working Interest (“WI”) Structure

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Successor Acquisitions and Divestitures

2017 Acquisitions

Acquisition of Properties. On February 10, 2017, the Company acquired assets consisting of approximately 13,000 net

acres in Woodward County, Oklahoma for approximately $ 47.8 million in cash, net of post-closing adjustments. Also included in the acquisition were working interests in four wells previously drilled on the acreage.

2017 Divestitures

2017 Property Divestitures. In 2017, the Company divested various non-core oil and natural gas properties for

approximately $ 17.1 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.

Predecessor Acquisitions and Divestitures

2016 Divestiture

Divestiture of West Texas Overthrust Properties and Release from Treating Agreement. In January 2016, the Company paid $ 11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the 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 ).

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The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, other current assets, accounts payable and accrued expenses and other current liabilities included in the unaudited condensed consolidated balance sheets approximated fair value at December 31, 2017 , and December 31, 2016 . As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment and related impairments, which are calculated using Level 3 inputs, are discussed in Note 9 .

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in Level 1 and Level 2 of the hierarchy as of December 31, 2017 and 2016 , 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 of $ 5.1 million and $ 2.8 million are included in other current assets at December 31, 2017 and December 31, 2016 , respectively, and investments of $ 4.8 million are included in other assets at December 31, 2016 , in the accompanying consolidated balance sheets. The Company’s non-qualified deferred compensation plan was terminated and all remaining investment balances were distributed to participants in January 2018.

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 6 .

The PGC Senior Secured Notes were issued at a substantial discount 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 prepayment 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

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

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the notes into shares of Predecessor 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. Th e significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion features at December 31, 2015 are 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

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, 2017 - Successor

	Fair Value Measurements												Netting(1)				Assets/Liabilities at Fair Value
	Level 1				Level 2				Level 3
Assets
Commodity derivative contracts	$	—			$	5,582			$	—			$	( 4,272	)		$	1,310
Investments	$	5,072			$	—			$	—			$	—			$	5,072
	$	5,072			$	5,582			$	—			$	( 4,272	)		$	6,382
Liabilities
Commodity derivative contracts	$	—			$	18,467			$	—			$	( 4,272	)		$	14,195
	$	—			$	18,467			$	—			$	( 4,272	)		$	14,195

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

____________________

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

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

		Predecessor
		Period from January 1, 2016 through October 1, 2016
Beginning balance		$	29,355
Gain on derivative holder conversion feature		( 880		)
Conversions		( 21,194		)
Write off of derivative holder conversion feature to reorganization items		( 7,281		)
Ending level 3 debt holder conversion feature balance		$	—

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, 2017 , 2016 and 2015 , 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 measured the fair value of its previously outstanding non-interest bearing 0.00 % Convertible Senior Subordinated Notes due 2020, (the “Convertible Notes”) using pricing that was readily available in the public market. The Successor Company measures the fair value of its $ 35.0 million initial principal note, as amended in February 2017, which is secured by first priority mortgages on the Company’s real estate in Oklahoma City, Oklahoma (the “Building Note”) using a discounted cash flow analysis, which is classified as a Level 2 input in the fair value hierarchy. The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands):

	December 31, 2017								December 31, 2016
	Fair Value				Carrying Value				Fair Value				Carrying Value
Convertible Notes	$	—			$	—			$	334,800			$	268,780
Building Note	$	42,526			$	37,502			$	40,608			$	36,528

See Note 12 for discussion of the Company’s long-term debt.

Fair Value of Non-Financial Assets and Liabilities

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

	December 31,
	2017				2016
Oil, natural gas and NGL sales	$	34,570			$	42,631
Joint interest billing	26,496				17,338
Oil and natural gas services	639				736
Other	10,846				14,272
Total accounts receivable	72,551				74,977
Less: allowance for doubtful accounts	( 1,274		)		( 880		)
Total accounts receivable, net	$	71,277			$	74,097

The following table presents the balance and activity in the allowance for doubtful accounts for the year ended December 31, 2017 , the Successor 2016 Period, the Predecessor 2016 Period and year ended December 31, 2015 (in thousands):

	Successor									Predecessor
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Beginning balance	$	880			$	—				$	4,847			$	7,083
Additions charged to costs and expenses(1)	397				880					16,695				1,320
Deductions(2)	( 3		)		—					( 751		)		( 3,556		)
Impact of fresh start accounting	—				—					( 20,791		)		—
Ending balance	$	1,274			$	880				$	—			$	4,847

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(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 the write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2016 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement and deductions in 2015 are related to the sale of the Gulf of Mexico and Gulf Coast oil and natural gas properties.

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

	December 31,
	2017				2016
Oil and natural gas properties
Proved	$	1,056,806			$	840,201
Unproved	100,884				74,937
Total oil and natural gas properties	1,157,690				915,138
Less accumulated depreciation, depletion and impairment	( 460,431		)		( 353,030		)
Net oil and natural gas properties capitalized costs	697,259				562,108
Land	4,500				5,100
Electrical infrastructure	131,010				130,242
Non-oil and natural gas equipment	26,809				35,768
Buildings and structures	79,548				88,603
Total	241,867				259,713
Less accumulated depreciation and amortization	( 15,886		)		( 3,889		)
Other property, plant and equipment, net	225,981				255,824
Total property, plant and equipment, net	$	923,240			$	817,932

The net carrying value of the Company’s oil and natural gas properties was reduced by $ 319.1 million during the Successor 2016 Period, $ 657.4 million during the Predecessor 2016 Period and $ 4.5 billion during 2015, as a result of quarterly full cost ceiling analyses in the respective periods. No full cost ceiling impairments were recorded in the 2017 period. See Note 10 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 $ 7.92 per Boe in 2017 , $ 8.31 per Boe for the Successor 2016 Period, $ 6.05 per Boe in the Predecessor 2016 Period and $ 10.81 per Boe in 2015 .

The Company has approximately $ 10.6 million in assets classified as held for sale in the other current assets line of the accompanying consolidated balance sheet at December 31, 2017. Approximately $ 9.3 million of this total is related to one of the Company’s properties located in downtown Oklahoma City, OK, which was classified as held for sale in the fourth quarter of 2017 and is expected to be sold during the first half of 2018. The remaining balance largely consists of the Company’s remaining drilling and oilfield services assets. These assets had a carrying value of $ 6.9 million which exceeded the net realizable value of $ 2.9 million determined by expected sales prices obtained from third parties. As a result, the Company recorded an impairment of $ 4.0 million for the year ended December 31, 2017 . The Company disposed of approximately $ 1.7 million of these assets during the year ended December 31, 2017 , and recorded an insignificant gain on sale of assets which is included in other operating expenses in the accompanying consolidated statement of operations. The Company expects to dispose of the majority of the remaining assets within the next year.

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Costs Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties, which were excluded from oil and natural gas properties subject to amortization at December 31, 2017 (in thousands):

					Year Cost Incurred
	Total				2017				2016				2015				2014 and Prior
Property acquisition	$	96,450			$	42,827			$	15,610			$	19,481			$	18,532
Exploration	4,434				1,904				678				1,453				399
Total costs incurred	$	100,884			$	44,731			$	16,288			$	20,934			$	18,931

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As deemed necessary based on events in 2017 , 2016 and 2015 , 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
		Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Full cost pool ceiling limitation(1)(2)		$	—			$	319,087				$	657,392			$	4,473,787
Drilling assets(3)(4)		4,019				—					3,511				37,646
Electrical infrastructure assets(5)		—				—					55,600				—
Midstream assets(6)		—				—					1,691				7,148
Other(7)		—				—					—				16,108
		$	4,019			$	319,087				$	718,194			$	4,534,689

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(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 recorded in the year ended 2017 reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value.

(4)	Impairment recorded in the Predecessor 2016 Period 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.

(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 year ended December 31, 2015 resulted from the evaluation of certain midstream pipe inventory, natural gas compressors, gas treating plants and a carbon dioxide (“CO 2 ”) 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 consist of the following (in thousands):

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

	December 31,				December 31,
	2017				2016
Credit facility	$	—			$	—
Convertible Notes	—				268,780
Building Note	37,502				36,528
Total debt	37,502				305,308
Less: current maturities of long-term debt	—				—
Long-term debt	$	37,502			$	305,308

On the Emergence Date, the Predecessor Company’s outstanding debt was canceled. See Note 1 for additional information regarding the bankruptcy proceedings.

Credit Facility. On February 10, 2017, the $ 425.0 million reserve-based revolving credit facility (the “First Lien Exit Facility”) was refinanced and replaced by a new $ 600.0 million credit facility (the “credit facility”). The borrowing base under the credit facility is $ 425.0 million . This borrowing base was reconfirmed during the October 2017 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, 2018. The credit facility matures on March 31, 2020. The outstanding borrowings under the credit facility bear interest based on a pricing grid tied to borrowing base utilization of (a) LIBOR plus an applicable margin that varies from 3.00 % to 4.00 % per annum, or (b) the base rate plus an applicable margin that varies from 2.00 % to 3.00 % per annum. Interest on base rate borrowings is payable quarterly in arrears and interest on LIBOR borrowings is payable every one, two, three or six months, at the election of the Company. Quarterly, the Company pays commitment fees assessed at annual rates of 0.50 % on any available portion of the credit facility. The Company has the right to prepay loans under the credit facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans. Upon refinancing of the First Lien Exit Facility, $ 50.0 million maintained in a restricted cash collateral account, as required by the terms of the First Lien Exit Facility, was released to the Company.

The 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).

Beginning with the quarter ended June 30, 2017, the credit facility requires the Company to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. The Company was in compliance with all applicable financial covenants under the credit facility as of December 31, 2017 .

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The credit facility also 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 Company was in compliance with these covenants as of December 31, 2017 .

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

The Company had no amounts outstanding under the credit facility at December 31, 2017 and $ 6.7 million in outstanding letters of credit, which reduce availability under the credit facility on a dollar-for-dollar basis.

First Lien Exit Facility. On the Emergence Date, the Company entered into the First Lien Exit Facility with the lenders party thereto and Royal Bank of Canada, as administrative agent and issuing lender.

The borrowing base under the First Lien Exit Facility was $ 425.0 million . The First Lien Exit Facility was set to mature on February 4, 2020. The outstanding borrowings under the First Lien Exit Facility bore interest at a rate equal to, at the option of the Company, either (a) a base rate plus an applicable rate of 3.75 % per annum or (b) LIBOR plus 4.75 % per annum, subject to a 1.00 % LIBOR floor. Interest on base rate borrowings was payable quarterly in arrears and interest on LIBOR borrowings was payable every one, two, three or six months, at the election of the Company. Quarterly, the Company was committed to pay fees assessed at annual rates of 0.50 % on any available portion of the First Lien Exit Facility. The Company had the right to prepay loans under the First Lien Exit Facility at any time without a prepayment penalty, other than customary “breakage” costs with respect to LIBOR loans.

The First Lien Exit Facility contained certain financial covenants and customary affirmative and negative covenants. The Company was in compliance with all applicable covenants through the date it was refinanced.

Convertible Notes. As discussed in Note 1, on the Emergence Date, pursuant to the terms of the Plan, the Company issued approximately $ 281.8 million principal amount of Convertible Notes, which did not bear regular interest and were set to mature and mandatorily convert into shares of common stock in the Successor Company (“the Common Stock”) on October 4, 2020, unless repurchased, redeemed or converted prior to that date. The Convertible Notes were recorded at their fair value of $ 445.7 million upon implementation of fresh start accounting. The resulting premium of $ 163.9 million was deemed significant to the principal amount of the Convertible Notes, and as such, was recorded in additional paid in capital in the condensed consolidated balance sheet at December 31, 2016. The Company’s obligations pursuant to the Convertible Notes were fully and unconditionally guaranteed, jointly and severally, by each of the guarantors of the First Lien Exit Facility.

The Convertible Notes were initially convertible at a conversion rate of 0.05330841 shares of Common Stock per $1.00 principal amount of Convertible Notes, which represented, in the aggregate, approximately 15.0 million shares of common stock. The conversion rate for the New Convertible Notes was subject to customary anti-dilution adjustments.

The 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. Between the Emergence Date and December 31, 2016, approximately $ 13.0 million in aggregate principal amount of the Convertible Notes was converted into approximately 0.7 million shares of Common Stock following delivery of voluntary conversion notices by the holders of those Convertible Notes. Additionally, during the period from January 1, 2017 to February 9, 2017, approximately $ 5.1 million in aggregate principal amount of the Convertible Notes was converted into approximately 0.3 million shares of Common Stock following delivery of voluntary conversion notices by the holders of those Convertible Notes. The remaining $ 263.7 million par value of outstanding Convertible Notes mandatorily converted into 14.1 million shares of Common Stock upon the refinancing of the First Lien Exit Facility on February 10, 2017, after the determination by the Successor Company’s board of directors in good faith that: (a) the refinancing provided for terms that were materially more favorable to the Company and (b) causing a conversion was not the primary purpose of the refinancing.

Building Note . As discussed in Note 1 , on the Emergence Date, the Company entered into the Building Note, which had an initial principal amount of $ 35.0 million . The Building Note was recorded at a fair value of $ 36.6 million upon implementation of fresh start accounting. The resulting premium is being amortized to interest expense over the term of the Building Note. Interest is payable on the Building Note at 6 % per annum for the first year following the Emergence Date, 8 % per annum for the second year following the Emergence Date, and 10 % thereafter through maturity. Interest costs were paid in kind and added to the Building

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Note principal from the Emergence Date through May 11, 2017, which was 90 days after the refinancing or repayment of the First Lien Exit Facility. Interest became payable thereafter in cash. The Building Note matures on October 2, 2021 and became prepayable in whole or in part without premium or penalty upon the refinancing of the First Lien Exit Facility. Net proceeds of $ 26.8 million received from the sale of the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan.

Maturities of Long-Term Debt

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. The Company has not designated any of its derivative contracts as hedges for accounting purposes and records all derivative contracts at fair value with changes in derivative contract fair values recognized in (gain) loss on derivative contracts in the condensed consolidated statements of operations. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Commodity derivative contracts are settled on a monthly basis. On a quarterly basis, the commodity derivative contract valuations are adjusted to the mark-to-market valuation. At December 31, 2017 , 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 Successor Company recorded (gain) loss on commodity derivative contracts of $( 24.1 ) million and $ 25.7 million for the year ended December 31, 2017 and the Successor 2016 Period, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash receipts upon settlement of $ 7.3 million and $ 7.7 million , respectively.

The Predecessor Company recorded loss (gain) on commodity derivative contracts of $ 4.8 million and $( 73.1 ) million for the Predecessor 2016 Period and the year ended December 31, 2015 , respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash receipts upon settlement of $ 72.6 million and $ 327.7 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.

Derivatives Agreements with Royalty Trusts. During the year ended December 31, 2015, the Company was party to derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II to provide each of the Royalty Trusts 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.

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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, 2017 , the counterparties to the Company’s open commodity derivative contracts consisted of seven financial institutions, all of which are also lenders under the Company’s credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as all of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s credit facility.

The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the credit facility as of December 31, 2017 and the First Lien Exit Facility as of December 31, 2016 (in thousands):

December 31, 2017

		Gross Amounts				Gross Amounts Offset				Amounts Net of Offset				Financial Collateral				Net Amount
Assets
Derivative contracts - current		$	5,582			$	( 4,272	)		$	1,310			$	—			$	1,310
Derivative contracts - noncurrent		—				—				—				—				—
Total		$	5,582			$	( 4,272	)		$	1,310			$	—			$	1,310
Liabilities
Derivative contracts - current		$	14,899			$	( 4,272	)		$	10,627			$	( 10,627	)		$	—
Derivative contracts - noncurrent		3,568				—				3,568				( 3,568		)		—
Total		$	18,467			$	( 4,272	)		$	14,195			$	( 14,195	)		$	—

December 31, 2016

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

At December 31, 2017 , the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)			Weighted Average Fixed Price
January 2018 - December 2018	3,464			$	55.08
January 2019 - December 2019	1,460			$	53.34

Natural Gas Price Swaps

	Notional (MMcf)			Weighted Average Fixed Price
January 2018 - December 2018	17,300			$	3.16

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Fair Value of Derivatives

The following table presents the fair value of the Company’s derivative contracts on a gross basis without regard to same-counterparty netting (in thousands):

				December 31,				December 31,
Type of Contract		Balance Sheet Classification		2017				2016
Derivative assets
Oil price swaps		Derivative contracts - current		$	—			$	—
Natural gas price swaps		Derivative contracts - current		5,582				—
Oil price swaps		Derivative contracts - noncurrent		—				—
Natural gas price swaps		Derivative contracts - noncurrent		—				—
Derivative liabilities
Oil price swaps		Derivative contracts - current		( 14,899		)		( 13,395		)
Natural gas price swaps		Derivative contracts - current		—				( 14,143		)
Oil price swaps		Derivative contracts - noncurrent		( 3,568		)		( 2,105		)
Natural gas price swaps		Derivative contracts - noncurrent		—				( 71		)
Total net derivative contracts				$	( 12,885	)		$	( 29,714	)

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

	Successor									Predecessor
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Beginning balance	$	106,481			$	92,413				$	103,578			$	54,402
Liability incurred upon acquiring and drilling wells	1,336				121					505				1,662
Revisions in estimated cash flows(1)	( 28,565		)		12,397					—				44,060
Liability settled or disposed in current period(2)	( 11,308		)		( 540		)			( 36,979		)		( 1,023		)
Accretion	9,600				2,090					4,365				4,477
Impact of fresh start accounting	—				—					20,944				—
Ending balance	77,544				106,481					92,413				103,578
Less: current portion	41,017				66,154					65,678				8,399
Asset retirement obligations, net of current	$	36,527			$	40,327				$	26,735			$	95,179

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(1)	Revisions for the year ended December 31, 2017, the Successor 2016 Period and the year ended December 31, 2015 relate primarily to changes in estimated well lives and changes in oil and natural gas prices.

(2)	Liability settled or disposed for the Predecessor 2016 Period includes $ 34.1 million associated with the WTO Properties sold in January 2016.

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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, 2017 , 2016 and 2015 . Employee termination benefits were $ 4.8 million for the year ended December 31, 2017 , $ 12.3 million for the Successor 2016 Period and $ 18.4 million for the Predecessor 2016 Period, primarily as a result of reductions in workforce. For the year ended December 31, 2015, employee termination benefits were $ 12.5 million , primarily as a result of a reduction in workforce and certain executives’ separation from employment.

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 13 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 credit facility to fund its capital expenditures. Based on its cash balances, cash flows from operating activities and net borrowing availability under the credit facility, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the next year; however, if 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.

Litigation and Claims. On October 14, 2016, Lisa West and Stormy Hopson filed an amended 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 amended complaint, plaintiffs asserted various tort claims seeking relief for damages, including the reimbursement of past and future earthquake insurance premiums, resulting from seismic activity allegedly caused by the defendants’ operation of wastewater disposal wells. The court dismissed the plaintiffs’ amended complaint on May 12, 2017, but permitted the plaintiffs to file a second amended complaint. On July 18, 2017, the plaintiffs filed a second amended class action complaint making allegations substantially similar to those contained in the amended complaint that was previously dismissed. An estimate of reasonably possible losses associated with this action can not be made at this time. The Company has not established any reserves relating to this action.

Successor Equity

Common Stock. As discussed in Note 1 , on the Emergence Date, the previously issued Predecessor Company common stock was canceled and an aggregate of approximately 18.9 million shares of Common Stock, par value $ 0.001 per share, was issued to the holders of allowed claims, as defined in the Plan. Approximately 0.4 million shares of Common Stock were reserved for future distributions under the Plan and approximately 0.1 million of the reserved shares were issued during the year ended December 31, 2017 . Additionally, from the Emergence Date through February 9, 2017, voluntary conversions of Convertible Notes resulted in the issuance of approximately 1.0 million shares of Common Stock. The remaining balance of Convertible Notes converted to 14.1 million shares of Common Stock upon refinancing of the First Lien Exit Facility. See Note 12 for further discussion of the Convertible Notes.

Shareholder Rights Plan. On November 26, 2017, the Company’s Board adopted a short-term shareholder rights plan, which was further amended on January 22, 2018, (the “Rights Plan”). The Rights Plan will be triggered only if a person or group of persons exceeds beneficial ownership of 15 % or more of the Company’s common stock. The Company intends to recommend the ratification of the Rights Plan for approval by its shareholders at the Company’s 2018 annual meeting of shareholders. If ratified by the shareholders, the Rights Plan will expire on November 26, 2018. If the Rights Plan is not ratified, then it will terminate and cease to be effective.

Warrants. A s discussed in Note 1 , on the Emergence Date, the Company issued approximately 4.9 million Series A Warrants, 4.5 million of which were issued immediately upon emergence, and 2.1 million Series B Warrants, 1.9 million of which

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were issued immediately upon emergence. Warrants not issued immediately upon emergence were held in reserve for the future settlement of general unsecured claims under the Plan. The Warrants were initially exercisable for one share of Common Stock per Warrant at initial exercise prices of $ 41.34 and $ 42.03 per share, respectively, subject to adjustments pursuant to the terms of the Warrants, to certain holders of general unsecured claims as defined in the Plan. Approximately 0.1 million Series A Warrants and an insignificant amount of Series B Warrants were issued under the Plan during the year ended December 31, 2017 . 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.

Shares Withheld for Taxes. The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired.

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

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 Company ceased accruing dividends on its 8.5 % and 7.0 % convertible perpetual preferred stock as of May 16, 2016, in conjunction with the Chapter 11 petition filings.

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

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

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

See Note 20 for discussion of the Company’s earnings (loss) 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 .

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. The Company had 2.1 million shares of such common stock held in treasury at December 31, 2015. 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.

Redemption of Senior Unsecured Notes. During the year ended December 31, 2015, the Predecessor Company issued approximately 28.0 million shares of common stock in exchange for $ 50.0 million in Senior Unsecured Notes.

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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 17 for discussion of the Company’s share-based compensation.

Shares Withheld for Taxes. The following table shows the number of shares withheld for taxes and the associated value of those shares (in thousands). These shares were accounted for as treasury stock when withheld, and then immediately retired.

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

Successor Share-Based Compensation

Omnibus Incentive Plan. The SandRidge Energy, Inc. 2016 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) became effective on the Emergence Date after the cancellation of the Predecessor Company’s share-based compensation awards. The Omnibus Incentive Plan authorizes the issuance of up to 4.6 million shares of SandRidge Common Stock.

Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of Common Stock, as well as certain cash-based awards. At December 31, 2017 , the Company had restricted stock awards, performance share units and performance units outstanding under the Omnibus Incentive Plan. Forfeitures for these awards are recognized as they occur.

Restricted Stock Awards. The Successor Company’s restricted stock awards are equity-classified awards and are valued based upon the market value of the Company’s Common Stock on the date of grant. 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. In 2017, awards for approximately 0.7 million shares were granted, which will vest over a period of approximately 2.5 years.

The Successor Company recognized total share-based compensation expense related to its restricted stock awards of $ 16.6 million and $ 6.6 million , of which $ 2.0 million and $ 0.3 million were capitalized, for the year ended December 31, 2017 and the Successor 2016 Period, respectively. Share-based compensation expense for the year ended December 31, 2017 , includes $ 1.8 million for the accelerated vesting of 0.1 million restricted common stock awards. 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.

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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
Granted	671			$	19.97
Vested	( 827	)		$	23.23
Forfeited / Canceled	( 146	)		$	23.52
Unvested restricted shares outstanding at December 31, 2017	1,105			$	22.62

As of December 31, 2017 , the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $ 21.4 million . The remaining weighted-average contractual period over which this compensation cost may be recognized is 1.8 years. The aggregate intrinsic value of restricted stock that vested during 2017 was approximately $ 16.0 million based on the stock price at the time of vesting.

Performance Share Units. In February 2017, the Company granted equity-classified awards in the form of performance share units, which will vest upon completion of the stated performance period from January 1, 2017 through June 30, 2019. The performance share units will be settled in Common Stock with one share of Common Stock being issued per performance share unit up to a maximum of approximately 0.4 million shares of Common Stock, provided the required performance measures are met. The shares are valued based on the Company’s performance relative to certain performance and market conditions. For the year ended December 31, 2017 , the Successor Company recognized total share-based compensation expense related to its performance share units of $ 1.4 million , of which $ 0.2 million was capitalized.

Successor Incentive-Based Compensation

Performance Units. In October 2016, the Company granted liability-classified awards in the form of performance units, which will vest over a three-year period and will be settled in cash, provided the required performance measures are met. The performance units were issued at a value of $ 100 each and the value at vesting will be determined by annual scorecard results. At December 31, 2017 , the liability related to performance units was $ 3.1 million . Additionally, the Successor Company recognized total incentive-based compensation expense related to its performance units of $ 2.6 million , of which $ 0.4 million was capitalized for the year ended December 31, 2017 .

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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, 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	—			$	—

2017 Annual Incentive Plan. The 2017 Annual Incentive Plan (“AIP”) incorporated quantitative performance measures, strategic qualitative goals and competitive target award levels for management and employees for the 2017 performance year. Potential payout percentages ranged from 0 % to 200 % of specified target levels based on actual performance. As of December 31, 2017, the Company had accrued approximately $ 10.8 million for the AIP for all employees, including an accrual for specified members of management. Payments will be made based on actual performance as determined by the Board of Directors relative to the targets specified in the plan in the first quarter of 2018.

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 and approximately $ 15.8 million during the first quarter of 2017.

401(k) Plan. The Company maintains a 401(k) retirement plan for its employees. Under this plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by Internal Revenue Service (“IRS”) regulations. For the year ended December 31, 2017 , the Successor Company made matching contributions to the plan equal to 100 % on the first 10 % of employee deferred wages, excluding incentive compensation, totaling $ 3.6 million . For the Successor 2016 Period, the Successor Company made matching cash contributions to the plan equal to 100 % on the first 10 % of 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 % of employee deferred wages for the period tot aling $ 4.9 million . For the year ended

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December 31, 2015 , the Predecessor Company made matching contributions to the plan through cash purcha ses of Predecessor Company stock equal to 100 % on the first 10 % of employee deferred wages. Retirement plan expense for the years ended December 31, 2015 was approximately $ 7.9 million . 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.

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

	Successor									Predecessor
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Current
Federal	$	( 8,719	)		$	—				$	—			$	—
State	( 30		)		9					11				123
	( 8,749		)		9					11				123
Deferred
Federal	—				—					—				—
State	—				—					—				—
	—				—					—				—
Total (benefit) provision	( 8,749		)		9					11				123
Less: income tax provision attributable to noncontrolling interest	—				—					—				90
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	( 8,749	)		$	9				$	11			$	33

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

	Successor									Predecessor
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Computed at federal statutory rate	$	13,409			$	( 116,891	)			$	504,283			$	( 1,512,325	)
State taxes, net of federal benefit	( 284		)		( 3,696		)			10,512				( 19,988		)
Non-deductible expenses	1,711				144					462				816
Non-deductible debt costs	—				—					22,694				10,228
Stock-based compensation	1,109				306					5,884				6,700
Net effects of consolidating the non-controlling interests’ tax provisions	—				—					—				218,196
Discharge of debt and other reorganization related items	1,018				—					359,278				—
Return to provision adjustments (1)	341,681				—					—				—
Impact of legislative changes	243,801				—					—				—
Release of valuation allowance	( 8,719		)		—					—				—
Change in valuation allowance	( 602,452		)		120,144					( 903,102		)		1,296,405
Other	( 23		)		2					—				1
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	( 8,749	)		$	9				$	11			$	33

____________________

(1)	Primarily related to the Company’s decision to file its 2016 income tax returns using an alternate method than previously estimated with respect to its Chapter 11 related transactions. See additional discussion with respect to Internal Revenue Code (“IRC”) Section 382 below.

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. The Company’s deferred tax assets have been reduced by a valuation allowance due to a determination made that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. During the year ended December 31, 2017 , the Company reduced the valuation allowance associated with deferred tax assets

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related to alternative minimum tax (“AMT”) credits that became realizable as a result of a special tax election. Accordingly, the Company recorded an income tax benefit of $ 8.7 million in the year ended December 31, 2017. As a result of the significant weight placed on the Company’s cumulative negative earnings position, the Company continued to maintain the full valuation allowance against its remaining net deferred tax asset at December 31, 2017 . As of December 31, 2017 , 2016 and 2015 , the balance of the valuation allowance was $ 0.5 billion , $ 1.1 billion , and $ 2.0 billion , respectively.

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

	December 31, 2017				December 31, 2016
Deferred tax liabilities
Investments(1)	$	171,517			$	275,128
Total deferred tax liabilities	171,517				275,128
Deferred tax assets
Property, plant and equipment	391,273				751,683
Derivative contracts	3,131				11,274
Allowance for doubtful accounts	986				1,487
Net operating loss carryforwards	217,259				527,079
Compensation and benefits	5,700				14,494
Tax Credits and other carryforwards	33,001				43,770
Asset retirement obligations	18,843				40,399
Other	2,273				4,663
Total deferred tax assets	672,466				1,394,849
Valuation allowance	( 500,949		)		( 1,119,721		)
Net deferred tax liability	$	—			$	—

____________________

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

The “Tax Cuts and Jobs Act” (the “TCJA”) enacted in December 2017 includes significant changes to the taxation of business entities, most of which are effective for taxable years beginning after December 31, 2017. These changes include, among others, a permanent reduction to the corporate income tax rate from a maximum 35% to a flat 21% rate, expansion of expensing capital expenditures for a period of time, new limitations on the utilization of net operating losses, and limitations on the deduction of interest expense and executive compensation. Based on our analysis of the TCJA and guidance currently available we recorded an income tax expense of approximately $ 243.8 million in the period ended December 31, 2017, which was completely offset by a decrease in the corresponding valuation allowance. The provisional amount primarily related to the remeasurement of our gross deferred tax assets and liabilities existing at December 31, 2017 at the appropriate tax rate expected to exist at the time of their reversal. We continue to evaluate the impact of the TCJA and while adjustments to certain deferred tax assets may occur in 2018 due to additional guidance or changes in estimates, we do not expect a material adjustment to our existing net deferred tax balance.

IRC Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, 2016. 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 on its tax attributes and previously planned to elect an available alternative upon filing its 2016 U.S. federal income tax return that would not subject existing tax attributes to an immediate IRC Section 382 limitation, but which would have resulted in a full limitation should a subsequent ownership change occur within two years of the emergent date ownership change. Alternatively, upon filing its 2016 U.S. federal income tax return, the Company elected a method that did subject tax attributes including net operating losses (“NOLs”) existing at October 4, 2016 to an annual limitation but provided more certainty with respect to the future availability of the Company’s existing NOLs. This limitation is expected to result in a significant portion of our NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance are materially less at December 31, 2017 compared to December 31, 2016. The election and resulting limitation did not result in an income tax expense as the Company’s net deferred tax asset had previously been reduced to zero by a valuation allowance. Additionally, the limitation did not result in a tax liability for the tax years ended December 31, 2016 or December 31, 2017.

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As of December 31, 2017 , the Company had approximately $ 4.7 million of alternative minimum tax credits available that do not expire. However, due to a special tax election available, the AMT credits are reflected as a current receivable as of December 31, 2017 . In addition, the Company had approximately $ 805.3 million of federal net operating loss carryovers, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation, that expire during the years 2025 through 2037 .

At December 31, 2017 and 2016 , the Company had an insignificant liability for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	Successor									Predecessor
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016
Unrecognized tax benefit at January 1	$	84			$	81				$	81
Changes to unrecognized tax benefits related to a prior period	2				3					—
Lapse of statute of limitations	( 38		)		—					—
Unrecognized tax benefit at December 31	$	48			$	84				$	81

Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included insignificant amounts of accrued gross interest with respect to unrecognized tax benefits in its accompanying consolidated statements of operations during the years ended December 31, 2017 , 2016 and 2015 . The Company expects a lapse in statute of limitation to eliminate its gross unrecognized tax benefits balance within the next 12 months .

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

The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share:

	Net Income (Loss)				Weighted Average Shares			Earnings (Loss) Per Share
	(In thousands, except per share amounts)
Year Ended December 31, 2017 (Successor)
Basic earnings per share	$	47,062			32,442			$	1.45
Effect of dilutive securities
Restricted stock awards	—				221
Performance share units(1)	—				—
Warrants(1)	—				—
Diluted earnings per share	$	47,062			32,663			$	1.44
Period from October 2, 2016 to December 31, 2016 (Successor)
Basic loss per share	$	( 333,982	)		18,967			$	( 17.61	)
Effect of dilutive securities
Restricted stock(2)	—				—
Warrants(2)	—				—
Convertible Notes(3)	—				—
Diluted loss per share	$	( 333,982	)		18,967			$	( 17.61	)
Period from January 1, 2016 to October 1, 2016 (Predecessor)
Basic earnings per share	$	1,424,476			708,928			$	2.01
Effect of dilutive securities
Restricted stock and units(4)	—				—
Diluted earnings per share	$	1,424,476			708,928			$	2.01
Year Ended December 31, 2015 (Predecessor)
Basic loss per share	$	( 3,735,495	)		521,936			$	( 7.16	)
Effect of dilutive securities
Restricted stock and units(4)	—				—
Convertible preferred stock (5)	—				—
Convertible senior unsecured notes(6)	—				—
Diluted loss per share	$	( 3,735,495	)		521,936			$	( 7.16	)

____________________

(1)	No incremental shares of potentially dilutive performance share units or warrants were included for the year ended December 31, 2017 , as their effect was antidilutive. See Note 17 for discussion of the Company’s share and incentive-based compensation awards.

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

(3)	Potential common shares related to the Convertible Notes covering 14.6 million shares for the Successor 2016 Period were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

(4)	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.

(5)	Potential common shares related to the Predecessor Company’s then-outstanding 8.5 % and 7.0 % convertible perpetual preferred stock covering 71.2 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.

(6)	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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Executive Team and Organizational Restructuring. On February 8, 2018, the Company announced the departure of James Bennett, President and CEO, effective immediately, and Julian Bott, Chief Financial Officer, effective at the close of business on the date of filing this 2017 Annual Report with the SEC. Simultaneously, the Company announced the appointment of independent board member, Bill Griffin, as Interim President and Chief Executive Officer, and the appointment of Sylvia K. Barnes as an independent director, effective February 8, 2018, and the appointment of Chief Accounting Officer, Michael Johnson, as Interim Chief Financial Officer, effective upon the departure of Mr. Bott.

Additionally, on February 8, 2018, the Company announced its new strategic direction, which includes implementing changes in the organizational structure and a reduction in planned 2018 capital expenditures and general and administrative expenses.

Merger proposal. On February 6, 2018, the Company received an unsolicited proposal from Midstates Petroleum Company, Inc. (“Midstates”) to combine SandRidge and Midstates in an all stock merger transaction. On February 7, 2018, the Company announced that its board of directors, in consultation with independent financial and legal advisers, will carefully review and evaluate Midstates’ proposal, taking into account the Company’s current strategic plan and standalone prospects.

Shareholder activism. Subsequent to the announcement of the Bonanza Creek Energy, Inc. merger in November 2017 , the Company has been actively engaged in ongoing discussions with its shareholders regarding the composition of the Company’s board of directors and the future direction of the Company. As a result of these discussions, the Company expects to incur significant additional costs related to shareholder activism including proxy fees charged by its independent financial adviser.

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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,					December 31,
	2017				2016					2015
Oil and natural gas properties
Proved	$	1,056,806			$	840,201				$	12,529,681
Unproved	100,884				74,937					363,149
Total oil and natural gas properties	1,157,690				915,138					12,892,830
Less accumulated depreciation, depletion and impairment	( 460,431		)		( 353,030		)			( 11,149,888		)
Net oil and natural gas properties capitalized costs	$	697,259			$	562,108				$	1,742,942

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):

	Successor									Predecessor
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Acquisitions of properties
Proved	$	7,092			$	5,142				$	3,897			$	35,376
Unproved	91,139				5,491					1,899				210,065
Exploration(1)	8,850				—					1,234				29,297
Development	187,264				27,429					149,924				571,562
Total cost incurred	$	294,345			$	38,062				$	156,954			$	846,300

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(1)	Includes 3-D seismic costs of $ 7.1 million for the year ended December 31, 2015 .

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Results of Operations for Oil and Natural Gas Producing Activities

The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the contribution to net earnings of the Company’s operations.

	Successor									Predecessor
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Revenues	$	356,210			$	98,307				$	279,971			$	707,434
Expenses
Production costs	116,372				27,640					135,715				324,141
Depreciation and depletion	118,035				36,061					90,978				324,390
Impairment	—				319,087					657,392				4,473,787
Total expenses	234,407				382,788					884,085				5,122,318
Income (loss) before income taxes	121,803				( 284,481		)			( 604,114		)		( 4,414,884		)
Income tax expense (benefit)(1)	47,722				( 112,427		)			( 229,986		)		( 1,680,746		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	74,081			$	( 172,054	)			$	( 374,128	)		$	( 2,734,138	)

____________________

(1)	Income tax expense (benefit) is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.

Oil, Natural Gas and NGL Reserve Quantities

Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:

•	the quality and quantity of available data and the engineering and geological interpretation of that data;

•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

•	the accuracy of mandated economic assumptions; and

•	the judgment of the personnel preparing the estimates.

Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

The 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

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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 2017 , 2016 and 2015 . 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. The remaining proved reserves were based on Company estimates.

The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

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

2016 Activity. During 2016, on a pro forma combined basis, 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 North Park Basin 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.

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

	Oil			NGL			Natural Gas			Total
	(MBbls)			(MBbls)			(MMcf)(1)			MBoe
Proved developed and undeveloped reserves
As of December 31, 2014(2) - Predecessor	126,031			91,786			1,788,233			515,856
Revisions of previous estimates	( 70,708	)		( 37,384	)		( 759,106	)		( 234,610	)
Acquisitions of new reserves	22,447			2,460			15,952			27,566
Extensions and discoveries	9,741			9,257			160,865			45,809
Production	( 9,600	)		( 5,044	)		( 92,104	)		( 29,995	)
As of December 31, 2015(2) - Predecessor	77,911			61,075			1,113,840			324,626
Adoption of ASU 2015-02	( 6,971	)		( 3,695	)		( 50,508	)		( 19,084	)
Revisions of previous estimates	( 39,973	)		( 21,475	)		( 415,568	)		( 130,709	)
Extensions and discoveries	987			472			7,955			2,785
Sales of reserves in place	( 387	)		—			( 145,267	)		( 24,598	)
Production	( 4,315	)		( 3,358	)		( 44,124	)		( 15,027	)
As of October 1, 2016 - Predecessor	27,252			33,019			466,328			137,992
Revisions of previous estimates	23,978			1,139			915			25,270
Extensions and discoveries	2,868			448			10,309			5,034
Production	( 1,214	)		( 999	)		( 12,770	)		( 4,341	)
As of December 31, 2016 - Successor	52,884			33,607			464,782			163,955
Revisions of previous estimates	804			2,628			44,679			10,879
Acquisitions of new reserves	18			70			683			202
Extensions and discoveries	12,446			1,914			30,080			19,373
Sales of reserves in place	( 204	)		( 529	)		( 7,055	)		( 1,909	)
Production	( 4,157	)		( 3,376	)		( 44,237	)		( 14,906	)
As of December 31, 2017 - Successor	61,791			34,314			488,932			177,594
Proved developed reserves
As of December 31, 2014 - Predecessor	79,022			56,823			1,203,447			336,420
As of December 31, 2015 - Predecessor	48,639			51,089			964,617			260,498
As of October 1, 2016 - Predecessor	24,541			30,238			428,050			126,121
As of December 31, 2016 - Successor	25,911			29,290			393,028			120,706
As of December 31, 2017 - Successor	25,845			29,922			407,988			123,765
Proved undeveloped reserves
As of December 31, 2014 - Predecessor	47,009			34,963			584,786			179,436
As of December 31, 2015 - Predecessor	29,272			9,986			149,223			64,129
As of October 1, 2016 - Predecessor	2,711			2,781			38,278			11,872
As of December 31, 2016 - Successor	26,973			4,317			71,754			43,249
As of December 31, 2017 - Successor	35,946			4,392			80,944			53,829

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(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

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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, 2017 , 2016 , and 2015 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,					December 31,
	2017				2016					2015
Oil (per barrel)	$	48.47			$	38.59				$	45.29
NGL (per barrel)	$	20.28			$	10.99				$	12.68
Natural gas (per Mcf)	$	1.90			$	1.56				$	1.87

•	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,					December 31,
	2017				2016					2015
Future cash inflows from production	$	4,621,615			$	3,136,762				$	6,387,944
Future production costs	( 1,837,852		)		( 1,454,798		)			( 2,731,542		)
Future development costs(1)	( 966,203		)		( 665,516		)			( 838,945		)
Future income tax expenses	( 107		)		( 142		)			( 901		)
Undiscounted future net cash flows	1,817,453				1,016,306					2,816,556
10% annual discount	( 1,068,159		)		( 577,942		)			( 1,501,994		)
Standardized measure of discounted future net cash flows(2)	$	749,294			$	438,364				$	1,314,562

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(1)	Includes abandonment costs.

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

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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
	Year Ended December 31, 2017				Period from October 2, 2016 through December 31, 2016					Period from January 1, 2016 through October 1, 2016				Year Ended December 31, 2015
Beginning present value	$	438,364			$	392,604				$	1,314,562			$	4,087,752
Changes during the year
Adoption of ASU 2015-02	—				—					( 224,965		)		—
Revenues less production	( 239,838		)		( 70,668		)			( 144,256		)		( 383,293		)
Net changes in prices, production and other costs	347,458				35,684					( 394,173		)		( 3,813,465		)
Development costs incurred	35,517				7,941					69,080				217,596
Net changes in future development costs	( 64,484		)		( 291,232		)			436,041				273,437
Extensions and discoveries	112,556				14,986					12,449				230,055
Revisions of previous quantity estimates	26,697				308,374					( 728,254		)		( 1,354,778		)
Accretion of discount	37,226				9,375					91,337				512,483
Net change in income taxes	23				—					402				1,426,333
Purchases of reserves in-place	454				—					—				18,429
Sales of reserves in-place	( 2,977		)		—					( 13,314		)		—
Timing differences and other(1)	58,298				31,300					( 26,305		)		100,013
Net change for the year	310,930				45,760					( 921,958		)		( 2,773,190		)
Ending present value(2)	$	749,294			$	438,364				$	392,604			$	1,314,562

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(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 attributable to noncontrolling interests at December 31, 2015.

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The Company’s operating results for each quarter of 2017 and 2016 are summarized below (in thousands, except per share data).

	Successor
	First Quarter				Second Quarter				Third Quarter				Fourth Quarter
2017
Total revenues	$	98,350			$	84,851			$	80,892			$	93,206
Income (loss) from operations(1)(2)	$	50,780			$	23,348			$	( 16,267	)		$	( 18,230	)
Net income (loss)(1)(2)	$	50,808			$	23,499			$	( 8,485	)		$	( 18,760	)
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders(1)(2)	$	50,808			$	23,499			$	( 8,485	)		$	( 18,760	)
Income available (loss applicable) per share to SandRidge Energy, Inc. common stockholders
Basic	$	1.90			$	0.69			$	( 0.25	)		$	( 0.54	)
Diluted	$	1.90			$	0.69			$	( 0.25	)		$	( 0.54	)

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(1)	Includes (gain) loss on derivative contracts of $( 34.2 ) million , $( 23.5 ) million , $ 11.7 million and $ 21.9 million for the first, second, third and fourth quarters, respectively.

(2)	Includes terminated merger costs of $ 8.2 million for the fourth quarter.

	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	)

____________________

(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 10 for further discussion of impairment.

(2)	Includes loss on settlement of contract of $ 89.1 million and gain on extinguishment of debt 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.

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