UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________

Form 10-Q

__________________________

(Mark One)



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

For the quarterly period ended September 30, ~~2017~~2018



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

For the transition period from to

Commission File Number: 001-33784

__________________________

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

__________________________



Delaware						20-8084793
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

123 Robert S. Kerr Avenue Oklahoma City, Oklahoma						73102
(Address of principal executive offices)						(Zip Code)

Registrant’s telephone number, including area code:

(405) 429-5500

Former name, former address and former fiscal year, if changed since last report: Not applicable

__________________________

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

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

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

~~(Do not check if a smaller reporting company)~~

Smaller reporting company

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on ~~October 27, 2017,~~November 2, 2018, was ~~35,647,066.~~

35,693,515.

Table of Contents

References in this report to the “Company,” “SandRidge,” “we,” “our,” and “us” mean SandRidge Energy, Inc., including its consolidated subsidiaries and its proportionately consolidated share of each of SandRidge Mississippian Trust I, SandRidge Mississippian Trust II and SandRidge Permian Trust (collectively, the “Royalty Trusts”).

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (“Quarterly Report”) of the Company includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning the Company’s capital expenditures, liquidity, capital resources and debt profile, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Company’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the effects thereof on the Company’s financial condition and other statements concerning the Company’s operations and financial performance and condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. The Company has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Company in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Company believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Company’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Company disclaims any obligation to update or revise these forward-looking statements unless required by law, and it cautions readers not to rely on them unduly. While the Company’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016~~2017 (the ~~“2016~~“2017 Form 10-K”) and in Item 1A of this Quarterly Report.

Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

FORM 10-Q

Quarter Ended September 30, ~~2017~~2018

INDEX

Table of Contents

PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except per share data)


	September 30, 2018		December 31, 2017
ASSETS
Current assets
Cash and cash equivalents	$	32,562	$	99,143

Restricted cash - other	1,912		2,165
Accounts receivable, net	54,493		71,277
Derivative contracts	73		1,310
Prepaid expenses	2,223		5,248
Other current assets	350		15,954
Total current assets	91,613		195,097
Oil and natural gas properties, using full cost method of accounting
Proved	1,206,363		1,056,806
Unproved	68,737		100,884
Less: accumulated depreciation, depletion and impairment	(546,769)		(460,431)
	728,331		697,259
Other property, plant and equipment, net	211,198		225,981

Other assets	1,181		1,290
Total assets	$	1,032,323	$	1,119,627

September 30,
2017 December 31,
2016
ASSETS
Current assets
Cash and cash equivalents $ 133,201
$ 121,231
Restricted cash - collateral —
50,000
Restricted cash - other 2,312
2,840
Accounts receivable, net 69,187
74,097
Derivative contracts 6,608
—
Prepaid expenses 2,334
5,375
Other current assets 8,045
3,633
Total current assets 221,687
257,176
Oil and natural gas properties, using full cost method of accounting
Proved 1,004,370
840,201
Unproved 103,533
74,937
Less: accumulated depreciation, depletion and impairment (432,564 ) (353,030 )
675,339
562,108
Other property, plant and equipment, net 238,420
255,824
Derivative contracts 2,010
—
Other assets 1,327
6,284
Total assets $ 1,138,783
$ 1,081,392



LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	112,980	$	139,155
Derivative contracts	36,905		10,627
Asset retirement obligation	40,041		41,017
Other current liabilities	7		8,115
Total current liabilities	189,933		198,914
Long-term debt	—		37,502
Derivative contracts	6,791		3,568
Asset retirement obligation	39,227		36,527
Other long-term obligations	3,837		3,176
Total liabilities	239,788		279,687
Commitments and contingencies (Note 11)
Stockholders’ Equity
Common stock, $0.001 par value; 250,000 shares authorized; 35,691 issued and outstanding at September 30, 2018 and 35,650 issued and outstanding at December 31, 2017	36		36
Warrants	88,517		88,500
Additional paid-in capital	1,054,155		1,038,324
Accumulated deficit	(350,173)		(286,920)
Total stockholders’ equity	792,535		839,940
Total liabilities and stockholders’ equity	$	1,032,323	$	1,119,627

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

Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED ~~BALANCE SHEETS~~STATEMENTS OF OPERATIONS (Unaudited) ~~- Continued~~

(In thousands, except per share data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018			2017
Revenues
Oil, natural gas and NGL	$	97,491	$	80,540	$	263,761		$	263,235
Other	169		352		489			858
Total revenues	97,660		80,892		264,250			264,093
Expenses
Production	23,429		26,765		68,927			76,997
Production taxes	5,636		3,606		14,725			9,435
Depreciation and depletion — oil and natural gas	33,090		31,029		92,048			87,486
Depreciation and amortization — other	3,036		3,399		9,229			10,729
Impairment	—		498		4,170			3,475
General and administrative	9,251		20,292		33,616			59,184
Accelerated vesting upon change in control	—		—		6,545			—
Proxy contest	(459)		—		7,139			—
Employee termination benefits	23		—		32,653			4,815
Loss (gain) on derivative contracts	11,329		11,702		59,763			(46,024)

Other operating (income) expense	(105)		(132)		(1,343)			135
Total expenses	85,230		97,159		327,472			206,232
Income (loss) from operations	12,430		(16,267)		(63,222)			57,861
Other (expense) income
Interest expense, net	(627)		(872)		(2,226)			(2,757)
Gain on extinguishment of debt	—		—		1,151			—

Other (expense) income, net	(118)		197		972			2,222
Total other expense	(745)		(675)		(103)			(535)
Income (loss) before income taxes	11,685		(16,942)		(63,325)			57,326
Income tax benefit	(30)		(8,457)		(72)			(8,496)
Net income (loss)	$	11,715	$	(8,485)	$	(63,253)		$	65,822


Earnings (loss) per share
Basic	$	0.33	$	(0.25)	$	(1.81)		$	2.07
Diluted	$	0.33	$	(0.25)	$	(1.81)		$	2.06
Weighted average number of common shares outstanding
Basic	35,308		34,290		34,971			31,750
Diluted	35,330		34,290		34,971			31,984

September 30,
2017 December 31,
2016
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses $ 127,941
$ 116,517
Derivative contracts 8
27,538
Asset retirement obligations 62,144
66,154
Other current liabilities 7,422
3,497
Total current liabilities 197,515
213,706
Long-term debt 37,601
305,308
Derivative contracts —
2,176
Asset retirement obligations 42,698
40,327
Other long-term obligations 2,686
6,958
Total liabilities 280,500
568,475
Commitments and contingencies (Note 8)

Stockholders’ Equity
Common stock, $0.001 par value; 250,000 shares authorized; 35,801 issued and outstanding at September 30, 2017 and 21,042 issued and 19,635 outstanding at December 31, 2016 36
20
Warrants 88,475
88,381
Additional paid-in capital 1,037,932
758,498
Accumulated deficit (268,160 ) (333,982 )
Total stockholders’ equity 858,283
512,917
Total liabilities and stockholders’ equity $ 1,138,783
$ 1,081,392

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

~~SANDRIDGE ENERGY, INC. AND SUBSIDIARIES~~

~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)~~

~~(In thousands, except per share data)~~

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
Revenues
Oil, natural gas and NGL $ 80,540
$ 99,934
$ 263,235
$ 279,971
Other 352
4,122
858
13,838
Total revenues 80,892
104,056
264,093
293,809
Expenses
Production 26,765
39,640
76,997
129,608
Production taxes 3,606
2,278
9,435
6,107
Depreciation and depletion—oil and natural gas 31,029
27,725
87,486
90,978
Depreciation and amortization—other 3,399
7,514
10,729
21,323
Impairment 498
354,451
3,475
718,194
General and administrative 20,292
29,145
63,999
134,447
Loss (gain) on derivative contracts 11,702
(338 ) (46,024 ) 4,823
Loss on settlement of contract —
—
—
90,184
Other operating (income) expense (132 ) 979
135
4,348
Total expenses 97,159
461,394
206,232
1,200,012
(Loss) income from operations (16,267 ) (357,338 ) 57,861
(906,203 )
Other (expense) income
Interest expense, net (872 ) (3,343 ) (2,757 ) (126,099 )
Gain on extinguishment of debt —
—
—
41,179
Reorganization items, net —
(42,754 ) —
(243,672 )
Other income (expense), net 197
(898 ) 2,222
1,332
Total other expense (675 ) (46,995 ) (535 ) (327,260 )
(Loss) income before income taxes (16,942 ) (404,333 ) 57,326
(1,233,463 )
Income tax (benefit) expense (8,457 ) 4
(8,496 ) 11
Net (loss) income (8,485 ) (404,337 ) 65,822
(1,233,474 )
Preferred stock dividends —
—
—
16,321
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders $ (8,485 ) $ (404,337 ) $ 65,822
$ (1,249,795 )
(Loss) earnings per share
Basic $ (0.25 ) $ (0.56 ) $ 2.07
$ (1.76 )
Diluted $ (0.25 ) $ (0.56 ) $ 2.06
$ (1.76 )
Weighted average number of common shares outstanding
Basic 34,290
718,373
31,750
708,788
Diluted 34,290
718,373
31,984
708,788

~~The accompanying notes are an integral part~~Table of ~~these condensed consolidated financial statements.~~Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (Unaudited)

(In thousands)


	Common Stock				Warrants				Additional Paid-In Capital				Accumulated Deficit	Total
	Shares	Amount		Shares	Amount
Nine Months Ended September 30, 2018
Balance at December 31, 2017	35,650	$	36	6,570	$	88,500	$	1,038,324	$	(286,920)	$	839,940
Issuance of stock awards, net of cancellations	15	—		—	—		—		—		—

Common stock issued for general unsecured claims	26	—		—	—		—		—		—
Stock-based compensation	—	—		—	—		23,224		—		23,224
Issuance of warrants for general unsecured claims	—	—		32	17		(17)		—		—
Cash paid for tax withholdings on vested stock awards	—	—		—	—		(7,376)		—		(7,376)
Net loss	—	—		—	—		—		(63,253)		(63,253)
Balance at September 30, 2018	35,691	$	36	6,602	$	88,517	$	1,054,155	$	(350,173)	$	792,535

Common Stock Warrants Additional Paid-In Capital Accumulated Deficit Total
Shares Amount Shares Amount

Nine Months Ended September 30, 2017
Balance at December 31, 2016 19,635
$ 20
6,442
$ 88,381
$ 758,498
$ (333,982 ) $ 512,917
Issuance of stock awards, net of cancellations 1,756
2
—
—
(2 ) —
—
Common stock issued for debt 14,328
14
—
—
268,765
—
268,779
Common stock issued for general unsecured claims 82
—
—
—
—
—
—
Stock-based compensation —
—
—
—
14,531
—
14,531
Issuance of warrants for general unsecured claims —
—
100
94
(94 ) —
—
Cash paid for tax withholdings on vested stock awards —
—
—
—
(3,766 ) —
(3,766 )
Net income —
—
—
—
—
65,822
65,822
Balance at September 30, 2017 35,801
$ 36
6,542
$ 88,475
$ 1,037,932
$ (268,160 ) $ 858,283

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)


	Nine Months Ended September 30,
	Successor			Predecessor				Nine Months Ended September 30,
	2017			2016				2018		2017
CASH FLOWS FROM OPERATING ACTIVITIES							CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	65,822		$	(1,233,474	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Net (loss) income							Net (loss) income	$	(63,253)	$	65,822
Adjustments to reconcile net (loss) income to net cash provided by operating activities							Adjustments to reconcile net (loss) income to net cash provided by operating activities
Provision for doubtful accounts	133			16,704			Provision for doubtful accounts	(6)		133
Depreciation, depletion and amortization	98,215			112,301
Depreciation, depletion, and amortization							Depreciation, depletion, and amortization	101,277		98,215
Impairment	3,475			718,194			Impairment	4,170		3,475
Reorganization items, net	—			231,836

Debt issuance costs amortization	313			4,996			Debt issuance costs amortization	352		313
Amortization of premiums and discounts on debt	(231		)	2,734			Amortization of premiums and discounts on debt	(47)		(231)
Gain on extinguishment of debt	—			(41,179		)	Gain on extinguishment of debt	(1,151)		—
Gain on debt derivatives	—			(1,324		)
Cash paid for early conversion of convertible notes	—			(33,452		)
(Gain) loss on derivative contracts	(46,024		)	4,823
Cash received on settlement of derivative contracts	7,700			72,608
Loss on settlement of contract	—			90,184
Cash paid on settlement of contract	—			(11,000		)

Loss (gain) on derivative contracts							Loss (gain) on derivative contracts	59,763		(46,024)
Cash (paid) received on settlement of derivative contracts							Cash (paid) received on settlement of derivative contracts	(29,025)		7,700

Stock-based compensation	12,616			9,075			Stock-based compensation	22,415		12,616
Other	188			(3,260		)	Other	(1,734)		188
Changes in operating assets and liabilities	5,699			(3,805		)	Changes in operating assets and liabilities	16,407		5,699
Net cash provided by (used in) operating activities	147,906			(64,039		)
Net cash provided by operating activities							Net cash provided by operating activities	109,168		147,906
CASH FLOWS FROM INVESTING ACTIVITIES							CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(152,743		)	(186,452		)	Capital expenditures for property, plant and equipment	(146,819)		(152,743)
Acquisition of assets	(48,236		)	(1,328		)	Acquisition of assets	—		(48,236)
Proceeds from sale of assets	19,769			20,090			Proceeds from sale of assets	14,497		19,769
Net cash used in investing activities	(181,210		)	(167,690		)	Net cash used in investing activities	(132,322)		(181,210)
CASH FLOWS FROM FINANCING ACTIVITIES							CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	—			489,198

Repayments of borrowings	—			(40,000		)	Repayments of borrowings	(36,304)		—
Debt issuance costs	(1,488		)	(333		)	Debt issuance costs	—		(1,488)
Cash paid for tax withholdings on vested stock awards	(3,766		)	(44		)	Cash paid for tax withholdings on vested stock awards	(7,376)		(3,766)
Net cash (used in) provided by financing activities	(5,254		)	448,821
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH	(38,558		)	217,092
Net cash used in financing activities							Net cash used in financing activities	(43,680)		(5,254)
NET DECREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH							NET DECREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH	(66,834)		(38,558)
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	174,071			435,588			CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	101,308		174,071
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period	$	135,513		$	652,680		CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period	$	34,474	$	135,513
Supplemental Disclosure of Cash Flow Information							Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items	$	—		$	(11,836	)
Cash received for income taxes							Cash received for income taxes	$	4,381	$	—
Supplemental Disclosure of Noncash Investing and Financing Activities							Supplemental Disclosure of Noncash Investing and Financing Activities
Cumulative effect of adoption of ASU 2015-02	$	—		$	(247,566	)
Property, plant and equipment transferred in settlement of contract	$	—		$	(215,635	)

Change in accrued capital expenditures	$	(15,241	)	$	25,045		Change in accrued capital expenditures	$	29,141	$	(15,241)
Equity issued for debt	$	(268,779	)	$	(4,409	)	Equity issued for debt	$	—	$	(268,779)

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

Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.1. Basis of Presentation

Nature of Business.SandRidge Energy, Inc. is an oil and natural gas exploration and production company headquartered in Oklahoma City, Oklahoma with its principal focus on developing high-return, growth-oriented projects in the U.S. Mid-Continent and North Park Basin of Colorado.

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 (the “Plan”) on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016 (the “Emergence Date”).

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

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements ~~as of December 31, 2016,~~and notes have been derived from the Company's 2017 Form 10-K and should be read in conjunction with the audited financial statements and notes contained in the Company’s ~~2016 Form 10-K. The unaudited condensed consolidated financial statements were also prepared in accordance with the accounting policies stated in the 2016~~2017 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, the financial statements include all adjustments, which consist of normal recurring adjustments unless otherwise disclosed, necessary to fairly state the Company’s unaudited condensed consolidated financial statements.

~~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 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, are not comparable with the financial statements prior to that date. References to the “Successor” or the “Successor Company” relate to SandRidge subsequent to October 1, 2016. References to the “Predecessor” or “Predecessor Company” refer to SandRidge on and prior to October 1, 2016.

Significant Accounting Policies. ~~For a description of the Company’s significant accounting policies, see Note 3 of the~~The unaudited condensed consolidated financial statements ~~included~~were prepared in accordance with the accounting policies stated in the ~~2016~~2017 Form 10-K as well as the items noted below.

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 unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and natural gas liquids (“NGL”) reserves; impairment tests of long-lived assets; depreciation, depletion and amortization; 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.

~~Table of Contents~~

~~SANDRIDGE ENERGY, INC. AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED~~

~~(Unaudited)~~

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. The Company early adopted this ASU for transactions effective after April 1, 2017. The guidance had no impact to the Company’s consolidated financial statements and related disclosures.

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.

~~Recent Accounting Pronouncements Not Yet Adopted.~~ ~~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~~deferred the effective date of ASU 2014-09 to January 1, 2018, for the ~~Company, with early adoption permitted in 2017.~~Company. The ASU ~~must be adopted~~required adoption using either the retrospective transition method, which ~~requires~~required restating previously reported results or the cumulative effect (modified retrospective) transition method, which ~~utilizes~~utilized a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company ~~plans to adopt~~adopted Topic 606 and all the ~~ASU~~related amendments (the “new revenue standard”) on January 1, 2018, using the modified retrospective transition method. See Note 2 for further discussion of the adoption of the new revenue standard.

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 is currently reviewing its contracts with customers and continues to evaluate the effect that the updated standard will have on its consolidated financial statements, accounting policies and related disclosures.

The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. Leases to explore for or use minerals, oil and natural gas are not impacted by this guidance. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for the Company on January 1, 2019. Early adoption is permitted. The Company plans to adopt the ASU on January 1, 2019 and continues to evaluate the effect that the guidance will have on its consolidated financial statements and related disclosures.

The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than ~~Inventory”~~Inventory,” which ~~removes~~removed 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~~were effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU ~~should be applied~~required application on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company ~~plans to adopt~~adopted the ASU on January 1, ~~2018 and continues~~2018. There was no impact to ~~evaluate~~ the ~~effect that the guidance will have on its~~Company’s consolidated financial ~~statements.~~statements and related disclosures upon adoption.

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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~~clarified that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company ~~plans to adopt~~adopted the ASU on January 1, 2018, using the modified retrospective transition method. Under this transition method the Company could have elected to apply this guidance retrospectively either to all contracts at the date of initial application or only to contracts that are not completed contracts at the date of initial application. The Company ~~continues~~elected to evaluate only contracts that are not completed contracts. As there were no uncompleted contracts at January 1, 2018, there was no impact to the ~~effect that the updated standard will have on its~~Company’s consolidated financial statements and related ~~disclosures.~~disclosures upon adoption.

~~2. Recent Transactions~~

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

Recent Accounting Pronouncements Not Yet Adopted. The FASB issued ASU 2016-02, “Leases (Topic 842),” which requires lessees to recognize the assets and liabilities for the rights and obligations of all leases with a term greater than 12 months (long-term) on the balance sheet. Leases will be classified as financing or operating expenses, with the classification affecting the pattern and classification of expense recognition in the income statement. Leases to explore for or use oil and natural gas are not impacted by this guidance. 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. ASU 2016-02 required adoption by application of a modified retrospective transition approach. In July 2018, the FASB issued ASU 2018-11, "Leases (Topic 842)." The amendments in this update provide another transition method whereby entities are allowed to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendments further provide lessors with a practical expedient, by class of underlying asset, to not separate nonlease components from the associated lease component, similar to the expedient provided for lessees. The lessor practical expedient is limited to circumstances in which the nonlease component or components otherwise would be accounted for under the new revenue guidance and both (1) the timing and pattern of transfer are the same for the nonlease component(s) and associated lease component and (2) the lease component, if accounted for separately, would be classified as an operating lease. The amendments also clarify whether Topic 842 or Topic 606 applies for combined components. This topic is effective for the Company on January 1, 2019. Early adoption is permitted.

Topic 842 provides a number of optional practical expedients in transition. The Company plans to elect the ‘package of practical expedients,’ which means the Company will not have to reassess under the new lease standard its prior conclusions about lease identification, lease classification and initial indirect costs. The Company also plans to elect the land easement practical expedient. The Company does not expect to elect the use-of-hindsight. Upon adoption, the Company anticipates recognizing assets and liabilities for the rights and obligations of its existing long-term operating leases on its consolidated balance sheets and utilizing new systems, processes and internal controls to properly identify, classify, measure and recognize new (or modified) leases after the date of adoption. While the effects of adoption are continuing to be assessed, the Company believes the primary impact of the lease standard relates to (1) recognizing assets and liabilities for the rights and obligations of the Company’s vehicle, drilling rig and equipment leases and, (2) providing new disclosures about the Company’s leasing activities. The Company will complete its evaluation during 2018 and will adopt Topic 842 on January 1, 2019. The Company expects to adopt this Topic using a modified retrospective approach by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption.

The new leasing standard also provides practical expedients for an entity’s ongoing accounting. The Company currently plans to elect the short-term lease recognition exemption for leases that qualify, which means the Company will not recognize assets and liabilities for the rights and obligations of qualifying leases, including existing short-term leases of those assets in

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transition. The Company is also currently evaluating applicability of the practical expedient to avoid separating lease and nonlease components for its leases.

2. Revenues

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

The following table disaggregates the Company’s revenue by source for the three and nine-month periods ended September 30, 2018 and 2017:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017

	(In thousands)
Oil	$	63,994	$	44,032	$	166,548	$	147,792
NGL	18,776		15,391		52,111		42,962
Natural gas	14,721		21,117		45,102		72,481
Other	169		352		489		858
Total revenues	$	97,660	$	80,892	$	264,250	$	264,093

Oil, natural gas and NGL revenues. A majority of the Company’s revenues come from sales of oil, natural gas and NGLs and are recorded at a point in time when control of the oil, natural gas and NGL production passes to the customer at the inlet of the processing plant or pipeline, or the delivery point for onloading to a delivery truck. As the Company’s customers obtain control of the production prior to selling it to other end customers, the Company presents its revenues on a net basis, rather than on a gross basis.

Pricing for the Company’s oil, natural gas and NGL contracts is variable and is based on volumes sold multiplied by either an index price, net of deductions, or a percentage of the sales price obtained by the customer, which is also based on index prices. The transaction price is allocated on a pro-rata basis to each unit of oil, natural gas or NGL sold based on the terms of the contract. Oil, natural gas and NGL revenues are also recorded net of royalties, discounts and allowances, and transportation costs, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from revenues and are included in production tax expense in the consolidated statements of operations.

Revenues Receivable. The Company records an asset in accounts receivable, net on its consolidated balance sheet for revenues receivable from contracts with customers at the end of each period. Pricing for revenues receivable is estimated using current month crude oil, natural gas and NGL prices, net of deductions. Revenues receivable are typically collected the month after the Company delivers the related production to its customers. As of September 30, 2018, and December 31, 2017, the Company had revenues receivable of $33.7 million and $34.6 million, respectively, and did not record any bad debt expense on revenues receivable during the three and nine-month periods ended September 30, 2018.

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

Most of the Company's contracts are short-term in nature with a contract term of one year or less. The Company generally expenses certain insignificant costs when incurred rather than recognizing them as an asset because the amortization period would have been one year or less. Additionally, the Company does not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, and (ii) contracts for which revenue is recognized at the amount to which the Company has the right to invoice for services performed. Payment terms are typically within 30 days of control being transferred.

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Currently, the Company’s existing contracts do not contain financing components, but the Company has elected the practical expedient that allows financing components to be ignored if the difference between the performance and payment is less than one year for any future contracts that may contain financing components.

3. Proxy Contest

In the second quarter of 2018, the Company received notification from Carl C. Icahn and certain affiliated entities (together, "Icahn"), that they intended to nominate a full slate of five candidates for election to the Board at the 2018 Annual Meeting of Stockholders (the "2018 annual meeting") that was held on June 19, 2018 (the "proxy contest"). The Company and Icahn, together with certain of their Board nominees, each entered into a ~~$200.0 million drilling participation~~settlement agreement ~~with a Counterparty~~pursuant to ~~jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of its undeveloped leasehold acreage within~~which the ~~Meramec formation in Major and Woodward Counties in Oklahoma (the “NW STACK”). Under this agreement, the Counterparty is paying 90%~~size of the Board was expanded to eight directors. The Board now consists of previously incumbent directors Sylvia K. Barnes, David J. Kornder and William M. Griffin, and newly elected members Bob G. Alexander, Jonathan Christodoro, Jonathan Frates, John J. "Jack" Lipinski and Randolph C. Read following the certification of the voting results, which occurred on June 22, 2018. As confirmed by external counsel, the election of a majority of non-incumbent directors nominated in connection with the proxy contest resulted in the accelerated vesting of certain share and incentive-based compensation awards granted to the Company's employees and directors as discussed further in Note 15.

The Company incurred legal, consulting and advisory fees related to shareholder activism and the proxy contest, as well as the review of strategic alternatives of $7.1 million for the nine-month period ended September 30, 2018, which is net ~~exploration~~of $(0.5) million in fees which were reimbursed to the Company during the three-month period ended September 30, 2018.

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4. Employee Termination Benefits

The following table presents a summary of employee termination benefits for the three and ~~development~~nine-month periods ended September 30, 2018 and 2017 (in thousands):


	Cash		Share-Based Compensation (4)		Number of Shares	Total Employee Termination Benefits
Three Months Ended September 30, 2018
Executive Employee Termination Benefits	$	—	$	—	—	$	—
Other Employee Termination Benefits	23		—		—	23
	$	23	$	—	—	$	23
Three Months Ended September 30, 2017
Executive Employee Termination Benefits	$	—	$	—	—	$	—
Other Employee Termination Benefits	—		—		—	—
	$	—	$	—	—	$	—
Nine Months Ended September 30, 2018
Executive Employee Termination Benefits (1)	$	11,945	$	9,196	554	$	21,141
Other Employee Termination Benefits (2)	7,577		3,935		209	11,512
	$	19,522	$	13,131	763	$	32,653
Nine Months Ended September 30, 2017
Executive Employee Termination Benefits (3)	$	2,500	$	1,825	96	$	4,325
Other Employee Termination Benefits	490		—		—	490
	$	2,990	$	1,825	96	$	4,815

____________________

1. On February 8, 2018, the Company’s then current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, the Company’s then current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, the Company incurred cash severance costs ~~up to $100.0 million~~and share-based compensation costs associated with the accelerated vesting of awards during the first quarter of 2018.

2. As a result of a reduction in workforce in the first ~~tranche, in exchange for an initial 80% net working interest in each new well, subject to~~quarter of 2018, certain ~~reversionary hurdles, as shown in~~employees received termination benefits including cash severance and accelerated share-based and incentive compensation vesting upon separation of service from the ~~table below. As a result,~~Company.

3. Includes cash severance costs and share-based compensation costs associated with the ~~Company is receiving a 20% net working interest after funding 10%~~accelerated vesting of ~~the exploration and development costs~~awards related to the ~~subject wells. This will allow~~departure of the ~~Company to spend minimal additional capital while accelerating~~Company's former Executive Vice President of Investor Relations and Strategy, Duane Grubert.

4. Share-based compensation recognized in connection with the ~~delineation~~accelerated vesting of ~~its position~~restricted stock awards and performance share units upon the departure of certain executives and the reduction in workforce in the ~~NW STACK, realizing further efficiencies~~first quarter of 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and ~~holding additional acreage by production, potentially adding reserves. The Company operates all~~performance share units. One share 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.Company’s common stock was issued per performance share unit.

~~Development Costs and Working Interest (“WI”) Structure~~



	~~Counterparty~~	~~SandRidge~~
~~Development Costs~~	~~90% of Costs~~	~~10% of Costs~~
~~Initial Working Interest~~	~~80% of WI~~	~~20% of WI~~
~~Reversion If Counterparty Achieves 10% IRR~~	~~35% of WI~~	~~65% of WI~~
~~Reversion If Counterparty Achieves 15% IRR~~	~~11% of WI~~	~~89% of WI~~

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

3
.

5. Acquisitions and Divestitures

Acquisition of Properties. OnIn February ~~10,~~ 2017, the Company acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately ~~$47.7~~$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 Property Divestitures. InDuring the nine-month period ended September 30, 2017, the Company ~~has~~ divested various non-core oil and natural gas properties for approximately $16.0 million in cash. All of these divestitures were accounted for as adjustments to the full cost pool with no gain or loss recognized.

~~Divestiture of West Texas Overthrust Properties and Release from Treating Agreement.~~ On January 21, 2016, the Predecessor 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 West Texas Overthrust (the “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. The Predecessor Company recognized a loss of approximately $89.1 million on the termination of the treating agreement and the cease-use of transportation agreements that supported production from the Piñon field.

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See Note 7 for discussion of significant fixed asset divestitures and Note 16 for discussion of acquisitions and divestitures subsequent to the balance sheet date.

6. Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy noted below. The carrying values of cash, restricted cash, accounts receivable, prepaid expenses, certain other current assets and other assets, accounts payable and accrued expenses, ~~and~~ other current liabilities and other long-term obligations included in the unaudited condensed consolidated balance sheets approximated fair value at September 30, ~~2017,~~2018, and December 31, ~~2016.~~2017. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment classified as assets held for sale and related impairments, which are calculated using Level 3 inputs, are discussed in Note 4.7.



Level 1			Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2			Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3			Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of 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 September 30, ~~2017~~,2018, and Level 1 and Level 2 as of December 31, ~~2016~~,2017, 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 ~~$4.9 million and $2.8~~$5.1 million are included in other current assets ~~at September 30, 2017, and December 31, 2016, respectively, and investments of $4.8 million are included in other assets at December 31, 2016,~~ in the accompanying unaudited condensed consolidated balance ~~sheets.~~sheet at December 31, 2017. 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.

~~Level 3 Fair Value Measurements~~

~~Debt Holder Conversion Feature~~. The Predecessor Company’s 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, the “Convertible Senior Unsecured Notes”) each contained a conversion option whereby, prior to Chapter 11 filings, the Convertible Senior Unsecured Notes holders had the option to convert the notes into shares of 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.

The fair values of the holder conversion features were determined using a binomial lattice model based on certain assumptions including (i) the Predecessor 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.

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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):

September 30, ~~2017~~2018


	Fair Value Measurements										Netting(1)	Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	224	$	—	$	(151)	$	73

	$	—	$	224	$	—	$	(151)	$	73
Liabilities
Commodity derivative contracts	$	—	$	43,847	$	—	$	(151)	$	43,696
	$	—	$	43,847	$	—	$	(151)	$	43,696

Fair Value Measurements Netting(1) Assets/Liabilities at Fair Value
Level 1 Level 2 Level 3
Assets
Commodity derivative contracts $ —
$ 9,641
$ —
$ (1,023 ) $ 8,618
Investments 4,918
—
—
—
4,918
$ 4,918
$ 9,641
$ —
$ (1,023 ) $ 13,536
Liabilities
Commodity derivative contracts $ —
$ 1,031
$ —
$ (1,023 ) $ 8
$ —
$ 1,031
$ —
$ (1,023 ) $ 8

December 31, ~~2016~~2017


	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value			Fair Value Measurements										Netting(1)	Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3							Level 1		Level 2		Level 3
Assets											Assets
Commodity derivative contracts											Commodity derivative contracts	$	—	$	5,582	$	—	$	(4,272)	$	1,310
Investments	$	7,541	$	—	$	—	$	—	$	7,541	Investments	5,072		—		—		—		5,072
	$	7,541	$	—	$	—	$	—	$	7,541		$	5,072	$	5,582	$	—	$	(4,272)	$	6,382
Liabilities											Liabilities
Commodity derivative contracts	$	—	$	29,714	$	—	$	—	$	29,714	Commodity derivative contracts	$	—	$	18,467	$	—	$	(4,272)	$	14,195
	$	—	$	29,714	$	—	$	—	$	29,714		$	—	$	18,467	$	—	$	(4,272)	$	14,195

____________________

~~(1)~~1. Represents the effect of netting assets and liabilities for counterparties with which the right of offset exists.

~~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):~~

Nine Months Ended September 30, 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 balance $ —

~~Prior to commencement of the Chapter 11 Proceedings, the fair value of the conversion features was 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.~~ The Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the three and ~~nine-month~~nine-month periods ended September 30, ~~2017,~~2018 and ~~2016.~~2017.

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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 iswas 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 Company repaid the Building Note in full during the first quarter of 2018. The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands):


	September 30, 2018						December 31, 2017
	Fair Value		Carrying Value		Fair Value		Carrying Value
Building Note	$	—	$	—	$	42,526	$	37,502

September 30, 2017 December 31, 2016
Fair Value Carrying Value Fair Value Carrying Value
Convertible Notes $ —
$ —
$ 334,800
$ 268,780
Building Note $ 41,638
$ 37,601
$ 40,608
$ 36,528

See Note 69 for additional discussion of the Company’s long-term debt.

5~~. Property, Plant and Equipment~~

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

September 30,
2017 December 31,
2016
Oil and natural gas properties
Proved $ 1,004,370
$ 840,201
Unproved 103,533
74,937
Total oil and natural gas properties 1,107,903
915,138
Less accumulated depreciation, depletion and impairment (432,564 ) (353,030 )
Net oil and natural gas properties capitalized costs 675,339
562,108

Land 5,200
5,100
Electrical infrastructure 131,100
130,242
Other non-oil and natural gas equipment 26,956
35,768
Buildings and structures 88,503
88,603
Total 251,759
259,713
Less accumulated depreciation and amortization (13,339 ) (3,889 )
Other property, plant and equipment, net 238,420
255,824
Total property, plant and equipment, net $ 913,759
$ 817,932

~~Impairments.~~ The Predecessor Company recorded impairments on its oil and natural gas properties of $298.0 million and $657.4 million during the three and nine-month periods ended September 30, 2016 as a result of its quarterly full cost ceiling analysis. No full cost ceiling impairments have been recorded in the 2017 period.

In the first quarter of 2017, the Company classified its remaining drilling and oilfield services assets as held for sale in the other current assets line of the unaudited condensed consolidated balance sheet. The net realizable value of the assets was determined to be $4.4 million based on expected sales prices obtained from a third party. The carrying value of these assets exceeded the net realizable value, resulting in impairments of $0.5 million and $3.5 million for the three and nine-month periods ended September 30, 2017. The Company disposed of approximately $0.8 million of these assets during the nine-month period ended September 30, 2017, and expects to dispose of the majority of the remaining assets during the fourth quarter of 2017.

~~The Company reviews non-oil and natural gas equipment and buildings and structures for recoverability whenever events~~

or changes in circumstances indicate that carrying amounts may not be recoverable. The Company recognizes an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. During the third quarter of 2016,

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7. Property, Plant and Equipment

Property, plant and equipment consists of the electrical transmission system was reviewed and was determined to not be recoverable due to a decrease in projected Mid-Continent production volumes supporting the system’s usage. Further, the carrying value exceeded its fair value. following (in thousands):


	September 30, 2018		December 31, 2017
Oil and natural gas properties
Proved	$	1,206,363	$	1,056,806
Unproved	68,737		100,884
Total oil and natural gas properties	1,275,100		1,157,690
Less accumulated depreciation, depletion and impairment	(546,769)		(460,431)
Net oil and natural gas properties capitalized costs	728,331		697,259

Land	4,500		4,500
Electrical infrastructure	131,010		131,010
Other non-oil and natural gas equipment	19,671		26,809
Buildings and structures	79,548		79,548
Total	234,729		241,867
Less accumulated depreciation and amortization	(23,531)		(15,886)
Other property, plant and equipment, net	211,198		225,981
Total property, plant and equipment, net	$	939,529	$	923,240

The Company ~~recorded an impairment~~had approximately $10.6 million in assets classified as held for sale in the other current assets line of ~~$55.6~~the accompanying consolidated balance sheet at December 31, 2017. Approximately $9.3 million ~~on its electrical transmission system~~of the total at December 31, 2017 was related to one of the Company’s properties located in downtown Oklahoma City, OK, which was classified as held for sale in the fourth quarter of 2017 and sold during the ~~three and nine-month periods ended September 30, 2016, and a $1.7~~second quarter of 2018 for approximately $10.4 million, ~~impairment~~net of transaction fees. The resulting gain of $1.1 million was recorded in other operating expense on ~~compressors and various other midstream services equipment during~~the accompanying condensed consolidated statements of operations for the nine-month period ended September 30, ~~2016, due primarily to~~2018.

Additionally, during the ~~determination that their future use was limited.~~

~~Fair value measurements for~~first quarter of 2018, the electrical asset impairment discussed above were based on replacement cost. As the fair value was estimated using the cost approach, inputs were based on the cost to a market participant buyer to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. These inputs were not observable in the market and wereCompany classified ~~as Level 3 in the fair value hierarchy.~~

~~The Company disposed of certain drilling and oilfield services~~its remaining midstream generator assets ~~previously classified~~ as held for ~~sale during 2016~~

~~and~~sale. These assets had a carrying value of $5.7 million which exceeded the estimated net realizable value of $1.6 million based on expected sales prices obtained from third parties. As a result, the Company recorded ~~losses on the sale~~an impairment of ~~those assets of $0.1 million and $1.7~~$4.1 million for the ~~three and~~ nine-month ~~periods~~period ended

September 30, ~~2016, which are included in other operating (income) expense in~~2018. The midstream generator assets were sold during the ~~accompanying unaudited condensed consolidated statements of operations.~~

~~Drilling Carry Commitments.~~ Under the terms of an agreement with Repsol E&P USA, Inc. (“Repsol”), the Predecessor Company had agreed to carry Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled in an area of mutual interest. Effective June 6, 2016, the Bankruptcy Court issued orders allowing the Company to reject certain long-term contracts, including this drilling carry commitment. Repsol filed a bankruptcy claim for this commitment, which was settled by the Company in the fourthsecond quarter of ~~2016 for approximately $1.2 million.~~2018 with no gain or loss recognized on the sale.

8. Accounts Payable and Accrued Expenses

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


	September 30, 2018		December 31, 2017
Accounts payable and other accrued expenses	$	54,957	$	75,191
Accrued interest	65		1,385
Revenues and royalties payable	42,075		37,274
Payroll and benefits	15,719		21,475
Drilling advances	164		3,830
Total accounts payable and accrued expenses	$	112,980	$	139,155

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9. Long-Term Debt

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”~~“credit facility”). The borrowing base under the ~~Credit Facility is~~credit facility was reduced from $425.0 ~~million. This borrowing base was reconfirmed~~million to $350.0 million during the October ~~2017~~2018 semi-annual redetermination. The next borrowing base redetermination is scheduled for April 1, ~~2018.~~2019. The ~~Credit Facility~~credit facility matures on March 31, 2020. The outstanding borrowings under the ~~Credit Facility~~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.~~credit facility. The Company has the right to prepay loans under the ~~Credit Facility~~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~~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~~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~~credit facility as of September 30, ~~2017.~~2018.

The ~~Credit Facility~~credit facility contains customary affirmative and negative covenants, including as to compliance with laws (including environmental laws, ERISA and anti-corruption laws), maintenance of required insurance, delivery of quarterly and annual financial statements, oil and gas engineering reports, maintenance and operation of property (including oil and gas properties), restrictions on the incurrence of liens, indebtedness, asset dispositions, fundamental changes, restricted payments including dividends and other customary covenants. The Company was in compliance with these covenants as of September 30, ~~2017.~~2018.

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The ~~Credit Facility~~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 credit facility also provides that a change in control, as defined therein, constitutes an event of default. In connection with the change in the majority of the members of the Company’s Board that occurred as a result of the 2018 annual meeting in June 2018, the Company entered into a consent and waiver agreement with the administrative agent and certain lenders constituting the majority lenders under the credit facility. The consent and waiver agreement waived any event of default which might have occurred as a result of the change in the majority of the members of the Company’s Board and recognized the new members of the Board as existing members of the Board under the definition of change in control in the credit agreement.

The Company had no amounts outstanding under the ~~Credit Facility~~credit facility at September 30, ~~2017,~~2018, and ~~$7.1~~$6.2 million in outstanding letters of credit, which reduce availability under the ~~Credit Facility~~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.~~ 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 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 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. On October 4, 2016 (the “Emergence Date”), in accordance with the ~~Emergence Date,~~joint plan of organization (the "Plan") of the Company and certain of its direct and indirect subsidiaries (collectively, the “Debtors"), 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~~Net proceeds of ~~$36.6~~$26.8 million ~~upon implementation of fresh start accounting. The resulting premium is being amortized to interest expense over~~received from the ~~term~~sale of the Building ~~Note.~~Note were remitted to unsecured creditors on the Emergence Date. The Company repaid the Building Note in full in February 2018. Interest iswas 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 Note principal from the Emergence Date through May 11, 2017, which was 90 days after the refinancing 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

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payable in-kind until 90 days after the refinancing of the First Lien Exit Facility, which was May 11, 2017, and approximately $1.3 million in in-kind interest costs were added to the Building Note principal from the Emergence Date. Interest became payable thereafter in cash. The Building Note was set to mature 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~~The Building Note was initially recorded at a fair value of ~~$26.8~~$36.6 million ~~received from~~upon implementation of fresh start accounting. Prior to repayment, the ~~sale~~resulting premium was being amortized to interest expense over the term of the Building ~~Note were subsequently remitted to unsecured creditors~~Note. Upon repayment, the remaining unamortized premium of $1.2 million was recognized as a gain on extinguishment of debt in the ~~Emergence Date in accordance with~~unaudited condensed consolidated statement of operations for the ~~Plan.~~nine-month period ended September 30, 2018.

7~~. Derivatives~~

10. Derivatives

Commodity Derivatives

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company, ~~seeks~~on occasion, has sought 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 inas gain or loss ~~(gain)~~ on derivative contracts in the unaudited 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 September 30, ~~2017,~~2018, the Company’s commodity derivative contracts consisted of fixed price swaps under which the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Company recorded losses on commodity derivative contracts of $11.3 million and $11.7 million for the three-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $11.6 million and $(5.0) million, respectively. The Company recorded loss (gain) on commodity derivative contracts of ~~$11.7~~$59.8 million and $(0.3) million for the three-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $5.0 million and $14.6 million, respectively. The Company recorded (gain) loss on commodity derivative contracts of $(46.0) ~~million and $4.8~~ million for the nine-month periods ended September 30, ~~2017,~~2018, and ~~2016,~~2017, respectively, which include net cash ~~receipts~~payments (receipts) upon settlement of ~~$7.7~~$29.0 million and ~~$72.6~~$(7.7) million, respectively. ~~Included in~~

On June 26, 2018, the ~~net cash receipts for~~Board suspended the ~~nine-month period ended September 30, 2016, is $17.9 million of cash receipts related~~Company's ability to ~~certain~~enter into new commodity derivative contracts ~~settled prior~~pending review. In November 2018, the Board concluded this comprehensive evaluation of its commodity derivatives program and determined that no action should be taken with respect to ~~their contractual maturities (“early settlements”).~~outstanding derivatives contracts at this time. Future derivative transactions will require Board approval.

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 in the unaudited condensed 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 September 30, ~~2017,~~2018, the counterparties to the Company’s open commodity derivative contracts consisted of ~~seven~~five financial institutions, all of which are also lenders under the Company’s ~~Credit Facility.~~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.~~credit facility.

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The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the ~~Credit Facility~~credit facility as of September 30, ~~2017,~~2018, and ~~the First Lien Exit Facility as of~~ December 31, ~~2016~~2017 (in thousands):

September 30, 2018


	Gross Amounts		Gross Amounts Offset		Amounts Net of Offset		Financial Collateral		Net Amount
Assets
Derivative contracts - current	$	224	$	(151)	$	73	$	—	$	73
Derivative contracts - noncurrent	—		—		—		—		—
Total	$	224	$	(151)	$	73	$	—	$	73
Liabilities
Derivative contracts - current	$	37,056	$	(151)	$	36,905	$	(36,905)	$	—
Derivative contracts - noncurrent	6,791		—		6,791		(6,791)		—
Total	$	43,847	$	(151)	$	43,696	$	(43,696)	$	—

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)	$	—

Gross Amounts Gross Amounts Offset Amounts Net of Offset Financial Collateral Net Amount
Assets
Derivative contracts - current $ 7,632
$ (1,024 ) $ 6,608
$ —
$ 6,608
Derivative contracts - noncurrent 2,009
1
2,010
—
2,010
Total $ 9,641
$ (1,023 ) $ 8,618
$ —
$ 8,618
Liabilities
Derivative contracts - current $ 1,031
$ (1,023 ) $ 8
$ (8 ) $ —
Total $ 1,031
$ (1,023 ) $ 8
$ (8 ) $ —

At September 30, 2018, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional (MBbls)	Weighted Average Fixed Price
October 2018 - December 2018	828	$	56.12
January 2019 - December 2019	1,825	$	54.29

Natural Gas Price Swaps


	Notional (MMcf)	Weighted Average Fixed Price
October 2018 - December 2018	3,680	$	3.11

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~~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 September 30, 2017, the Company’s open commodity derivative contracts consisted of the following:~~

~~Oil Price Swaps~~

Notional (MBbls)
Weighted Average
Fixed Price
October 2017 - December 2017 828
$ 52.24
January 2018 - December 2018 2,006
$ 54.87

~~Natural Gas Price Swaps~~

Notional (MMcf)
Weighted Average
Fixed Price
October 2017 - December 2017 8,280
$ 3.20
January 2018 - December 2018 17,300
$ 3.16

Fair Value of Derivatives

The following table presents the fair value of the Company’s derivative contracts as of September 30, ~~2017~~,2018, and December 31, ~~2016~~,2017, on a gross basis without regard to same-counterparty netting (in thousands):


Type of Contract	Balance Sheet Classification	September 30, 2018		December 31, 2017
Derivative assets

Natural gas price swaps	Derivative contracts-current	$	224	$	5,582


Derivative liabilities
Oil price swaps	Derivative contracts-current	(37,056)		(14,899)

Oil price swaps	Derivative contracts-noncurrent	(6,791)		(3,568)

Total net derivative contracts				$	(43,623)	$	(12,885)

Type of Contract Balance Sheet Classification September 30,
2017 December 31,
2016
Derivative assets
Oil price swaps Derivative contracts-current $ 5,417
$ —
Natural gas price swaps Derivative contracts-current 2,214
—
Oil price swaps Derivative contracts-noncurrent 1,739
—
Natural gas price swaps Derivative contracts-noncurrent 271
—
Derivative liabilities
Oil price swaps Derivative contracts-current (1,031 ) (13,395 )
Natural gas price swaps Derivative contracts-current —
(14,143 )
Oil price swaps Derivative contracts-noncurrent —
(2,105 )
Natural gas price swaps Derivative contracts-noncurrent —
(71 )
Total net derivative contracts $ 8,610
$ (29,714 )

See Note 46 for additional discussion of the fair value measurement of the Company’s derivative contracts.

8
.

11. Commitments and Contingencies

Legal Proceedings. 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

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complaint making allegations substantially similar to those contained in the amended complaint that was previously dismissed. On August 13, 2018, the court granted the Company’s motion to dismiss, thereby dismissing the Company from the lawsuit.

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

Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated cases (the “Cases”):

• In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma

• Ivan Nibur, Lawrence Ross, Jase Luna, Matthew Willenbucher, and the Duane & Virginia Lanier Trust v. SandRidge Mississippian Trust I, et al., Case No. 5:15-cv-00634-SLP, USDC, Western District of Oklahoma

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

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

In addition to the ~~matter~~matters described above, the Company is involved in various lawsuits, claims and proceedings which are being handled and defended by the Company in the ordinary course of business. Pursuant to the terms of the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II, the Company is obligated to indemnify each Royalty Trust against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters as stipulated in the respective agreements with each Royalty Trust.

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Restricted Cash. Restricted cash - other included on the unaudited condensed consolidated balance sheets at September 30, ~~2017,~~2018, and December 31, ~~2016~~2017 is the cash portion of consideration set aside for future settlement of general unsecured claims related to the Chapter 11 proceedings in accordance with the Plan. The corresponding liability for future cash settlements of general unsecured claims is included in accounts payable and accrued expenses on the unaudited condensed consolidated balance sheets.

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~~has historically entered into commodity derivative arrangements in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. The Company may not fully benefit from increases in the market price of oil and natural gas during periods where the strike prices for the Company's commodity derivative contracts are below market prices at the time of settlement. See Note 710 for the Company’s open oil and natural gas derivative contracts.

The Company historically has depended on cash flows from operating activities and, as necessary, borrowings under its ~~Credit Facility~~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,~~credit facility, the Company expects to be able to fund its planned capital expenditures budget, working capital needs, and any potential debt service requirements ~~and working capital needs~~ for the next year; however, if oil or natural gas prices decline from current levels, they could 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. Potential decreases in the Company's cash flows from operating activities during periods of declining market prices of oil and natural gas may be offset to the extent the Company has commodity derivative contracts in place that have strike prices above market prices at the time of settlement.

9.12. Equity

Common ~~Stock.~~Stock and Performance Share Units. OnAt September 30, 2018, the ~~Emergence Date, the previously issued Predecessor~~ Company ~~common stock was canceled and an aggregate of approximately 18.9~~had 35.7 million shares of ~~Common Stock,~~common stock, par value $0.001 per share, ~~was~~ issued ~~to the holders of allowed claims, as defined in the Plan. Approximately~~and outstanding, including 0.4 million shares of ~~Common Stock were reserved for future distributions under the Plan~~unvested restricted stock awards, and approximately 0.1 million of the reserved shares were issued during the three-month period ended September 30, 2017. Additionally, from the Emergence Date through February 9, 2017, voluntary conversions of Convertible Notes resulted in the issuance of approximately 1.0250.0 million shares of ~~Common Stock. The remaining balance~~common stock authorized. In accordance with normal practices, the Company granted additional restricted stock awards and an immaterial amount of ~~Convertible Notes converted to 14.1 million shares~~performance share units in the third quarter of ~~Common Stock~~2018.

Accelerated Vesting upon ~~refinancing~~Change in Control. As a result of the ~~First Lien Exit Facility.~~election of a majority of non-incumbent directors nominated in connection with the proxy contest in the second quarter of 2018, and on the advice of outside counsel, vesting was accelerated for the majority of the Company's then-outstanding unvested restricted stock awards and all of the Company's then-outstanding unvested performance share units. See Note 63 and Note 15 for ~~further~~additional discussion of ~~the Convertible Notes.~~this event.

Warrants. ~~On the Emergence Date, the~~The Company has issued approximately ~~4.9~~4.6 million Series A ~~Warrants, 4.5 million of which were issued immediately upon emergence,~~warrants and ~~2.1~~2.0 million Series B ~~Warrants, 1.9 million of which were issued immediately upon emergence (the “Warrants”). The Warrants were initially~~warrants that are exercisable until October 4, 2022 for one share of ~~Common Stock~~common stock per ~~Warrant~~warrant at initial exercise prices of $41.34 and $42.03 per share, respectively, subject to adjustments pursuant to the terms of the ~~Warrants,~~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 three-month period ended September 30, 2017.~~ The ~~Warrants are exercisable from the Emergence Date until October 4, 2022, and~~warrants contain customary anti-dilution adjustments in the event of any stock split, reverse stock split, reclassification, stock dividend or other distributions.

~~Predecessor Company Preferred Stock Dividends.~~ In the first quarter of 2016, prior to the February semi-annual dividend payment date, the Predecessor Company announced the suspension of the semi-annual dividend on its 8.5% convertible perpetual preferred stock. At September 30, 2016, the Company had dividends in arrears of $11.3 million and $21.0 million on its 8.5% and 7.0% convertible perpetual preferred stock, respectively. The Predecessor 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.

Paid and unpaid dividends included in the calculation of loss applicable to the Predecessor Company’s common stockholders and the Predecessor Company’s basic loss per share calculation for the nine-month period ended September 30, 2016 are presented in the unaudited condensed consolidated statement of operations. All outstanding shares of the Predecessor Company's

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(Unaudited)

~~8.5% and 7.0% convertible perpetual preferred stock were canceled upon Emergence from Chapter 11. See Note 11 for discussion of the Company’s loss (earnings) per share calculation.~~

~~10.~~13. Income Taxes

For each interim reporting period, the Company estimates the effective tax rate expected for the full fiscal year and uses that estimated rate in providing for income taxes on a current year-to-date basis. The provision for income taxes consisted of the following components (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
Current
Federal	$	(33)	$	(8,460)	$	(33)	$	(8,460)
State	3		3		(39)		(36)
Total provision	$	(30)	$	(8,457)	$	(72)	$	(8,496)

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
Current
Federal $ (8,460 ) $ —
$ (8,460 ) $ —
State 3
4
(36 ) 11
Total provision $ (8,457 ) $ 4
$ (8,496 ) $ 11

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 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 three-month period ended September 30, 2017, the Company reduced the valuation allowance associated with deferred tax assets related to alternative minimum tax (AMT) credits that became realizable as a result of a special tax election. Accordingly, the Company recorded an income tax benefit of $8.5 million in the three-month period ended September 30, 2017. As a result of the significant weight placed on the Company's cumulative negative earnings position, the Company continued to maintain a full valuation allowance against its ~~remaining~~ net deferred tax asset at September 30, ~~2017.~~2018. Thus, the Company’s effective tax rate and expense for the three and nine-month periods ended September 30, 2018 continue to be low.

The “Tax Cuts and Jobs Act” (the “TCJA”) enacted in December 2017 includes significant changes to the taxation of business entities, most of which are effective for taxable years beginning after December 31, 2017. These changes include, among others, a permanent reduction to the corporate income tax rate from a maximum 35% to a flat 21% rate, expansion of expensing capital expenditures for a period of time, new limitations on the utilization of net operating losses (“NOLs”), and limitations on the deduction of interest expense and executive compensation. We continue to evaluate the impact of the TCJA as new guidance and accounting interpretations become available and while adjustments to certain deferred tax assets may occur in 2018, we do not expect a material adjustment to the provisional amounts recorded for the year ended December 31, 2017 or the nine-month period ended September 30, 2018.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, ~~2016. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact~~2016 that subjected certain of the October 4, 2016 ownership change on its tax attributes. Previously, the Company planned to elect an available alternative upon filing its 2016 U.S. Federal income tax return that would not subject existingCompany’s tax attributes, including $1.9 billion of federal NOL carryforwards, to ~~an immediate~~the IRC Section 382 limitation but 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.limitation. This limitation is expected to result in ~~a significant portion~~$1.6 billion of ~~our~~the $1.9 billion of federal NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance ~~are expected to be materially less at~~were reduced in the period ended December 31, ~~2017, compared to December 31, 2016.~~2017. 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 by~~ a ~~valuation allowance. Additionally, the limitation did not result in a~~current tax liability for the tax year ended December 31, 2017 or the nine-month period ended September 30, 2018. Since the October 4, 2016 ~~and is~~ownership change the Company has generated additional NOLs that are not ~~expected~~currently subject to ~~result~~an IRC Section 382 limitation. See "Note 19 - Income Taxes" in athe 2017 Form 10-K for additional discussion with respect to the impact of income tax ~~liability for~~elections associated with the ~~tax year ending December 31, 2017.~~Chapter 11 reorganization.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years ~~2014~~2015 to present remain open for federal examination. Additionally, tax years 2005 through ~~2013~~2014 remain subject to examination for the purpose of determining the amount of remaining federal NOL and other carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years.

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(Unaudited)

14. Earnings (Loss) per Share

11
~~. (Loss) Earnings per Share~~

~~As discussed in Note 9, 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) ~~earnings~~ per share:


									Net Income (Loss)			Weighted Average Shares	Earnings (Loss) Per Share
	Net (Loss) Income			Weighted Average Shares	(Loss) Earnings Per Share
	(In thousands, except per share amounts)								(In thousands, except per share amounts)
Three Months Ended September 30, 2017 (Successor)
Basic loss per share	$	(8,485	)	34,290	$	(0.25	)
Three Months Ended September 30, 2018								Three Months Ended September 30, 2018
Basic earnings per share								Basic earnings per share	$	11,715		35,308	$	0.33
Effect of dilutive securities								Effect of dilutive securities
Restricted stock awards~~(1)~~	—			—				—			22
Performance share units(1)	—			—				Performance share units(1)	—			—
Diluted loss per share	$	(8,485	)	34,290	$	(0.25	)


Three Months Ended September 30, 2016 (Predecessor)
Warrants(2)								Warrants(2)	—			—
Diluted earnings per share								Diluted earnings per share	$	11,715		35,330	$	0.33
Three Months Ended September 30, 2017								Three Months Ended September 30, 2017
Basic loss per share	$	(404,337	)	718,373	$	(0.56	)	Basic loss per share	$	(8,485)		34,290	$	(0.25)
Effect of dilutive securities								Effect of dilutive securities
Restricted stock and units(2)	—			—
Restricted stock awards(3)								Restricted stock awards(3)	—			—
Performance share units(3)								Performance share units(3)	—			—
Warrants(2)								Warrants(2)	—			—
Diluted loss per share	$	(404,337	)	718,373	$	(0.56	)	Diluted loss per share	$	(8,485)		34,290	$	(0.25)


Nine Months Ended September 30, 2017 (Successor)
Nine Months Ended September 30, 2018								Nine Months Ended September 30, 2018
Basic loss per share								Basic loss per share	$	(63,253)		34,971	$	(1.81)
Effect of dilutive securities								Effect of dilutive securities
Restricted stock awards(4)								Restricted stock awards(4)	—			—
Performance share units(1)								Performance share units(1)	—			—
Warrants(2)								Warrants(2)	—			—
Diluted loss per share								Diluted loss per share	$	(63,253)		34,971	$	(1.81)
Nine Months Ended September 30, 2017								Nine Months Ended September 30, 2017
Basic earnings per share	$	65,822		31,750	$	2.07		Basic earnings per share	$	65,822		31,750	$	2.07
Effect of dilutive securities								Effect of dilutive securities
Restricted stock awards	—			234				Restricted stock awards	—			234
Performance share units(3)	—			—
Performance share units(1)								Performance share units(1)	—			—
Warrants(2)								Warrants(2)	—			—
Diluted earnings per share	$	65,822		31,984	$	2.06		Diluted earnings per share	$	65,822		31,984	$	2.06


Nine Months Ended September 30, 2016 (Predecessor)
Basic loss per share	$	(1,249,795	)	708,788	$	(1.76	)
Effect of dilutive securities
Restricted stock and units(2)	—			—
Diluted loss per share	$	(1,249,795	)	708,788	$	(1.76	)

____________________


~~(1)~~	Restricted stock awards covering 0.1 million shares and performance share units covering an insignificant amount of shares for the three-month period ended September 30, 2017, were excluded from the computation of loss per share because their effect would have been antidilutive. See Note 12 for discussion of the Company’s share and incentive-based compensation awards.


~~(2)~~	No incremental shares of potentially dilutive restricted stock awards or units were included for the three and nine-month periods ended September 30, 2016, as their effect was antidilutive under the treasury stock method. See Note 12 for discussion of the Company’s share and incentive-based compensation awards.


~~(3)~~	No incremental shares of potentially dilutive performance share units were included for the nine-month period ended September 30, 2017, as their effect was antidilutive under the treasury stock method. See Note 12 for discussion of the Company’s share and incentive-based compensation awards.

1. No incremental shares of potentially dilutive performance share units were included for the three-month period ended September 30, 2018, or the nine-month periods ended September 30, 2018, or 2017, as their effect was antidilutive under the treasury stock method.

2. No incremental shares of potentially dilutive warrants were included for the three and nine-month periods ended September 30, 2018, or 2017, as their effect was antidilutive.

3. Restricted stock awards covering 0.1 million shares and performance share units covering an insignificant amount of shares for the three-month period ended September 30, 2017, were excluded from the computation of loss per share because their effect would have been antidilutive.

4. No incremental shares of potentially dilutive restricted stock awards were included for the nine-month period ended September 30, 2018, as their effect was antidilutive under the treasury stock method.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

~~12.~~15. Share and Incentive-Based Compensation

~~Successor~~ Share-Based Compensation

Omnibus Incentive Plan. ~~Upon the Company’s emergence from bankruptcy, the Predecessor's share-based compensation awards were canceled and pursuant to terms of the Plan, the SandRidge Energy, Inc. 2016~~The Company's Omnibus Incentive Plan ~~(the “Omnibus Incentive Plan”)~~ became ~~effective.~~

~~Persons eligible to receive awards under the~~effective in October 2016. The Omnibus Incentive Plan ~~include~~authorizes the issuance of up to 4.6 million shares of SandRidge common stock to eligible persons including non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and ~~advisors~~advisers 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,~~the Company’s common stock, as well as certain ~~cash-based~~cash-settled awards. At September 30, ~~2017,~~2018, the Company had restricted stock awards and an immaterial amount of performance share ~~units and performance~~ units outstanding under the Omnibus Incentive Plan.

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~~common stock on the date of grant. ~~During October 2016, awards~~Vesting for ~~approximately 1.4 million shares of~~certain restricted stock ~~were~~awards was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018 with the majority of the remaining restricted stock awards vesting in June 2018 as a result of the accelerated vesting upon change in control event discussed in Note 3. In August 2018, the Company granted ~~under the Omnibus Incentive Plan. These~~additional restricted stock awards. Outstanding restricted shares will generally vest over either a one-year period or three-year period. In 2017, awards for approximately 0.6 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 $3.1 million and $13.5 million, of which $0.5 million and $1.8 million were capitalized, for the three and nine-month periods ended September 30, 2017, respectively. Share-based compensation expense for the nine-month period ended September 30, 2017, includes $1.8 million for the accelerated vesting of 0.1 million restricted common stock awards. The following table presents a summary of the ~~Successor~~ Company’s unvested restricted stock ~~awards.~~awards:


	Number of Shares	Weighted Average Grant Date Fair Value
	(In thousands)
Unvested restricted shares outstanding at December 31, 2017	1,105	$	22.62
Granted	366	$	16.06
Vested	(1,049)	$	22.71
Forfeited / Canceled	(39)	$	21.61
Unvested restricted shares outstanding at September 30, 2018	383	$	16.22

Number of
Shares
Weighted Average Grant Date Fair Value
(In thousands)
Unvested restricted shares outstanding at December 31, 2016 1,407
$ 24.32
Granted 640
$ 20.04
Vested (464 ) $ 22.41
Forfeited / Canceled (96 ) $ 23.52
Unvested restricted shares outstanding at September 30, 2017 1,487
$ 23.13

As of September 30, ~~2017,~~2018, the ~~Successor Company’s~~Company's unrecognized compensation cost related to unvested restricted stock awards ~~was $25.0~~totaled $5.6 million. The remaining ~~weighted-average~~weighted average contractual period over which this compensation cost may be recognized is ~~2.0~~2.4 years. The ~~Successor Company’s~~aggregate intrinsic value of restricted stock ~~awards are equity-classified awards.~~that vested during the nine-month period ended September 30, 2018 was approximately $15.9 million based on the stock price at the time of vesting.

Performance Share ~~Units.~~ Units. In February 2017, the Company granted equity-classified awards in the form of performance share units. The vesting for certain performance share units ~~which vest upon completion~~was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018 with all remaining units vesting in June 2018 as a result of the ~~performance period, which is January 1, 2017 through June 30, 2019. The~~accelerated vesting upon change in control event discussed in Note 3. All performance share units ~~will be~~for which vesting was accelerated were settled in ~~Common Stock, 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~~Company’s common stock with one share of ~~the Company Common Stock~~common stock being issued per performance share ~~unit as awarded~~unit. In September 2018, the Company granted an immaterial amount of additional performance share units. The following table presents a summary of the Company’s performance share units:


	Number of Units	Fair Value per Unit at September 30, 2018
	(In thousands)
Unvested performance share units outstanding at December 31, 2017	183
Granted	111
Vested	(177)
Forfeited / Canceled	(6)
Unvested performance share units outstanding at September 30, 2018	111	$	20.41

The aggregate intrinsic value of performance share units that vested during the nine-month period ended September 30, 2018 was approximately $2.7 million based on the Company’s performance relative to certain performance and market conditions. The Company’s performance share units are equity-classified awards. The Successor Company recognized total share-based compensation expense related to its performance share unitsstock price at the time of ~~$0.4 million and $1.0 million, of which $0.1 million and $0.2 million were capitalized, for the three and nine-month periods ended September 30, 2017, respectively.~~vesting.

~~Successor Incentive-Based Compensation~~

~~Performance Units.~~ In October 2016, the Company granted 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. The Company’s performance units are liability-classified awards. The Successor Company recognized total incentive-based compensation expense related to its performance units of $0.5 million and $2.1 million, of which $0.1 million and $0.3 million were capitalized, for the three and nine-month periods ended September 30, 2017, respectively. At September 30, 2017, the liability related to performance units was $2.5 million.

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(Unaudited)

~~Predecessor Share-Based~~Incentive-Based Compensation

Performance Units~~Restricted Common Stock Awards.~~ ~~Prior to~~. In October 2016, the ~~cancellation~~Company granted liability-classified awards in the form of performance units. The vesting for certain performance units was accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018 with all remaining units vesting in June 2018 as a result of the ~~Predecessor Company’s share-based compensation awards on~~accelerated vesting upon change in control acceleration event discussed in Note 3. The accelerated performance units were paid at the ~~Emergence Date, the then-existing restricted common stock awards generally vested over~~issuance value of $100 each. The value for previous vestings was determined by annual scorecard results. The following table presents a ~~four-year period, subject to certain conditions, and were valued based upon the market value~~summary of the Company’s ~~common stock on~~performance units:


	Number of Units	Fair Value per Unit at September 30, 2018
	(In thousands)
Unvested performance units outstanding at December 31, 2017	49
Granted	—
Vested	(48)
Forfeited / Canceled	(1)
Unvested performance units outstanding at September 30, 2018	—	—

The aggregate intrinsic value of performance units that vested during the ~~date~~nine-month period ended September 30, 2018 was approximately $4.8 million.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

The following tables summarize share and incentive-based compensation for the three and nine-month periods ended September 30, ~~2016,~~2018, and 2017 (in thousands):


	Recurring Compensation Expense(1)		Executive Terminations(2)		Reduction in Force(2)		Change in Control(3)		Total
Three Months Ended September 30, 2018
Equity-classified awards:
Restricted stock awards	$	523	$	—	$	—	$	—	$	523
Performance share units	41		—		—		—		41
Total share-based compensation expense	564		—		—		—		564



Less: Capitalized compensation expense	(58)		—		—		—		(58)
Share-based compensation expense, net	$	506	$	—	$	—	$	—	$	506

Three Months Ended September 30, 2017
Equity-classified awards:
Restricted stock awards	$	3,084	$	—	$	—	$	—	$	3,084
Performance share units	397		—		—		—		397
Total share-based compensation expense	3,481		—		—		—		3,481
Liability-classified awards:
Performance units	489		—		—		—		489
Total share and incentive-based compensation expense	3,970		—		—		—		3,970
Less: Capitalized compensation expense	(593)		—		—		—		(593)
Share and incentive-based compensation expense, net	$	3,377	$	—	$	—	$	—	$	3,377



Nine Months Ended September 30, 2018
Equity-classified awards:
Restricted stock awards	$	3,902	$	8,140	$	3,777	$	5,181	$	21,000
Performance share units	400		1,056		158		610		2,224
Total share-based compensation expense	4,302		9,196		3,935		5,791		23,224
Liability-classified awards:
Performance units	776		2,151		558		1,309		4,794
Total share and incentive-based compensation expense	5,078		11,347		4,493		7,100		28,018
Less: Capitalized compensation expense	(392)		—		—		(555)		(947)
Share and incentive-based compensation expense, net	$	4,686	$	11,347	$	4,493	$	6,545	$	27,071

Nine Months Ended September 30, 2017
Equity-classified awards:
Restricted stock awards	$	11,698	$	1,825	$	—	$	—	$	13,523
Performance share units	1,007		—		—		—		1,007
Total share-based compensation expense	12,705		1,825		—		—		14,530
Liability-classified awards:
Performance units	2,051		—		—		—		2,051
Total share and incentive-based compensation expense	14,756		1,825		—		—		16,581
Less: Capitalized compensation expense	(2,221)		—		—		—		(2,221)
Share and incentive-based compensation expense, net	$	12,535	$	1,825	$	—	$	—	$	14,360

____________________

1. Recorded in general and administrative expense in the accompanying consolidated statements of operations.

2. Recorded in employee termination benefits in the accompanying consolidated statements of operations.

3. Recorded in accelerated vesting upon change in control in the accompanying consolidated statements of operations.

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(Unaudited)

16. Subsequent Events

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

Acquisition of Oil and Natural Gas Interests. On November 2, 2018, the Company acquired certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $25.1 million, subject to ~~its restricted stock awards~~certain remaining post-closing adjustments. The acquired assets primarily consist of ~~$1.8 million and $11.2 million,~~interests in 1,962 wells, approximately 80% of which ~~$0.5 million~~are operated by the Company, an additional 13.2% working interest in approximately 410,000 gross (54,000 net) acres across the Mid-Continent, and ~~$1.7 million were capitalized, respectively. Share-based compensation expense for~~an additional 13.2% working interest ownership in the ~~nine-month period ended September 30, 2016, included $5.4 million for~~Company's saltwater gathering and disposal system in the accelerated vesting of 1.3 million restricted common stock awards related to the Predecessor Company’s reduction in workforce during the first quarter of 2016. There was no significant activity related to the Predecessor Company’s then-outstanding restricted stock units, performance units and performance share units during the three and nine-month periods ended September 30, 2016. The following table presents a summary of the Predecessor Company’s unvested restricted stock awards.Mississippian Lime.

Number of
Shares
Weighted-Average Grant Date Fair Value
(In thousands)
Unvested restricted shares outstanding at December 31, 2015 5,626
$ 4.85
Granted —
$ —
Vested (3,034 ) $ 5.34
Forfeited / Canceled (158 ) $ 6.25
Unvested restricted shares outstanding at September 30, 2016 2,434
$ 4.15

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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis is intended to help the reader understand our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our audited consolidated financial statements and the accompanying notes included in the ~~2016~~2017 Form 10-K. Our discussion and analysis includes the following subjects:

• Overview;

• Consolidated Results of Operations;

• Liquidity and Capital Resources; and

• Critical Accounting Policies and ~~Estimates; and~~

~~Valuation Allowance.~~

Estimates

The financial information with respect to the three and ~~nine-month~~nine-month periods ended September 30, ~~2017~~,2018, and ~~2016~~,2017, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments unless otherwise disclosed, necessary to state fairly the accompanying unaudited condensed consolidated financial statements. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

Overview

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

~~Voluntary Reorganization Under Chapter 11~~

On May 16, 2016, the Debtors filed the Bankruptcy Petitions for reorganization under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court. The Debtors’ Chapter 11 Cases were consolidated for procedural purposes only and are jointly administered under the caption In re: SandRidge Energy Inc., et al. The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization on September 9, 2016, and we subsequently emerged from bankruptcy on October 4, 2016.

~~Emergence from Voluntary Reorganization Under Chapter 11~~

~~The following significant transactions occurred upon our emergence from Chapter 11:~~


•	~~First Lien Credit Agreement.~~All outstanding obligations under the senior secured revolving credit facility (the “senior credit facility”) were canceled, and the $425.0 million First Lien Exit Facility was established. The First Lien Exit Facility was refinanced in February 2017 as discussed in “Liquidity and Capital Resources.”


•	~~Cash Collateral Account.~~ We deposited $50.0 million of cash collateral in an account controlled by the administrative agent to the First Lien Exit Facility. This deposit was released to us in February 2017 in conjunction with the refinancing of the First Lien Exit Facility as discussed in “Liquidity and Capital Resources.”

•

~~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 in October 2015, (collectively, the “Senior Secured Notes”) were canceled and exchanged for approximately 13.7 million of the 18.9 million shares of the Successor Company’s Common Stock, issued at emergence. Additionally, claims under the Senior Secured Notes received approximately $281.8 million principal value of Convertible Notes. The remaining principal outstanding on the Convertible Notes mandatorily converted into shares of Common Stock upon the refinancing of the First Lien Exit Facility in February 2017, as discussed in “Liquidity and Capital Resources.”


•	~~General Unsecured Claims.~~The Predecessor Company’s general unsecured claims, including the Senior Unsecured Notes and the Convertible Senior 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 and 2.1 million Series B Warrants. Approximately 4.5 million Series A Warrants and 1.9 million Series B Warrants were issued immediately upon emergence.


•	~~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.~~


•	~~Preferred and Common Stock.~~ ~~The Predecessor Company’s 7.0% and 8.5% convertible perpetual preferred stock and common stock were canceled and released under the Plan.~~

~~See “Note 6 - Long-Term Debt” and “Note 9 - Equity” to the accompanying unaudited condensed consolidated financial statements for additional information on the transactions noted above.~~

~~Fresh Start Accounting.~~ We elected to apply fresh start accounting effective October 1, 2016, to coincide with the timing of our normal fourth quarter reporting period, which resulted in SandRidge becoming a new entity for financial reporting purposes. In accordance with ASC 852, the reorganization value of the Successor Company was allocated to its individual assets based on their estimated fair values as of the Emergence Date.

As a result of the application of fresh start accounting and the effects of the implementation of the Plan, the statement of operations after October 1, 2016 (the “Successor 2016 Period”) may not be comparable with the statement of operations for the period from January 1, 2016 through October 1, 2016 (the “Predecessor 2016 Period”). However, our reorganization under Chapter 11 did not result in the divestiture of any of our oil and natural gas properties. As a result, certain operating results and key operating performance measures, including those related to production, average oil and natural gas selling prices, revenues and lease operating expenses, were not significantly impacted by the reorganization, and certain of the operating results in the Predecessor Period and the Successor Period are still comparable. For items that are not comparable, we have included additional analysis to supplement the discussion.

Operational Activities

Operational activities for the three and nine-month periods ended September 30, ~~2017,~~2018, and ~~2016~~2017 include the following:


	Three Months Ended September 30,
	2018					2017
	Gross Wells Drilled	Net Wells Drilled	Average Rigs Drilling	Gross Wells Drilled	Net Wells Drilled	Average Rigs Drilling
Area
Mid-Continent (1)	5	2.1	1.9	9	6.4	2.9
North Park Basin	—	—	0.3	3	3.0	1.0
Total	5	2.1	2.2	12	9.4	3.9


	Nine Months Ended September 30,
	2018					2017
	Gross Wells Drilled	Net Wells Drilled	Average Rigs Drilling	Gross Wells Drilled	Net Wells Drilled	Average Rigs Drilling
Area
Mid-Continent (1)	15	4.3	1.5	15	11.3	2.3
North Park Basin	8	8.0	0.6	4	4.0	0.5
Total	23	12.3	2.1	19	15.3	2.8

____________________

1. Three and 12 wells, respectively, were drilled under the drilling participation agreement during the three and nine-month periods ended September 30, 2018. One well was drilled under the drilling participation agreement during the three and nine-month periods ended September 30, 2017. Under this agreement, we are receiving a 20% net working interest after funding 10% of the drilling and completion costs related to the subject wells. The counterparty to the drilling participation agreement has been billed costs totaling $49.4 million for drilling and completion activity through September 30, 2018, under the initial $100.0 million tranche of the agreement.

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Total production for the three-month period ended September 30, ~~2017,~~2018, was comprised of approximately 30.6% oil, 46.7% natural gas and 22.7% NGLs compared to 26.7% oil, 50.7% natural gas and 22.6% NGLs ~~compared to 28.1% oil, 47.8% natural gas and 24.1% NGLs~~ in the same period of ~~2016.~~2017. Total production for the nine-month period ended September 30, ~~2017,~~2018, was comprised of approximately 28.4% oil, 48.9% natural gas and 22.7% NGLs compared to 27.5% oil, 49.6% natural gas and 22.9% NGLs ~~compared to 28.7% oil, 48.9% natural gas and 22.4% NGLs~~ in the same period of ~~2016.~~

~~Increased total rigs drilling to three at September 30, 2017, from one at September 30, 2016.~~

Drilled nine and 14 wells, respectively, in the Mid-Continent during the three and nine-month periods ended September 30, 2017, compared to three and 13 wells drilled during the same periods in 2016, respectively. Drilled four and six wells, respectively, in the North Park Basin during the three and nine-month periods ended September 30, 2017, compared to drilling two and 12 wells during the same periods in 2016, respectively.

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 2 - Recent Transactions” to the accompanying unaudited condensed consolidated financial statements for additional discussion of the drilling participation agreement.

~~Discontinued all remaining drilling and oilfield services operations in 2016, and as a result, our drilling and oilfield services operations no longer constituted a reportable segment in~~ 2017.

~~Transferred~~

Recent Events

Divestiture of Permian Basin Properties. On November 1, 2018, we sold substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO and $11.0 million in cash to Occidental in January 2016 in exchange for the release from all past, current and future claims and obligations under an existing 30-year treating agreement with Occidental. Our midstream and marketing operations no longer constitute a reportable segment in 2017.

On February 10, 2017, we acquired approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.7 million in cash. Also included in the acquisition were working interests in four wells previously drilled on the acreage.

~~Outlook~~

Based on the successful results of our drilling program in the North Park Basin and NW STACK during the first half of 2017, we increased our 2017 capital expenditures budget to a range between $250.0 million and $260.0 million in the second quarter of 2017 from the original range of $210.0 million to $220.0 million. The increase in capital expenditures is allowing for continued development of these assets in the fourth quarter of 2017 by funding (i) the establishment of two federal units and additional infrastructure in our North Park acreage, and (ii) the acquisition of 3D seismic and core analysis to support our NW STACK drilling program.

Although no impairment was indicated for our oil and natural gas properties during the third quarter of 2017, the commodity price environment in 2015 and 2016 resulted in the impairment of a significant portion of our oil and natural gas properties, ~~over recent reporting periods.~~rights and related assets in the CBP region of the Permian Basin, together with 13,125,000 common units of the Trust, to an independent third party for $14.5 million in cash, subject to certain remaining post-closing adjustments. This transaction did not result in a significant alteration of the relationship between our capitalized costs and proved reserves and, accordingly, the proceeds were recorded as a reduction of our full cost pool with no gain or loss recognized on the sale. We believe that exiting the CBP will simplify our portfolio and operations, and allow us to increase our focus on our core asset development strategy. See "Note 16 - Subsequent Events" for further discussion of this divestiture.

Acquisition of Oil and Gas Interests. On November 2, 2018, we acquired certain oil and natural gas properties, rights and related assets in the Mississippian Lime and NW STACK areas of Oklahoma and Kansas for approximately $25.1 million, subject to certain remaining post-closing adjustments. As of September 2018, these oil and gas properties had monthly net production of 3,775 barrels of oil per day. This transaction compliments and consolidates working interests in wells we currently operate, and therefore requires little effort to integrate into our operations. See "Note 16 - Subsequent Events" for further discussion of this acquisition.

CEO Search. On September 17, 2018, William M. Griffin, Jr., Interim President and CEO, informed the Board that he would not be a candidate to serve as the ongoing President and CEO. Mr. Griffin will continue serving as Interim President and CEO until a successor is appointed and will continue as a non-employee member of the Board thereafter. The ~~historical twelve-month unweighted average prices at~~Board has formed a search committee to evaluate and recommend to the Board candidates to serve as President and CEO following the departure of Mr. Griffin.

Terminated Poison Pill. On November 26, 2017, we entered into an agreement with American Stock Transfer & Trust Company, LLC (as amended by the First Amendment to the Stockholder Rights Agreement dated January 22, 2018, the "Poison Pill"). At our 2018 annual meeting in June 2018, the Poison Pill was terminated.

Proxy Contest. Prior to our 2018 annual meeting, Icahn proposed a slate of candidates for the Board, and our shareholders voted a majority of non-incumbent directors onto the Board. Subsequent to the shareholder vote, by agreement of all the request parties, the size of the Board was expanded to eight directors.

Executive terminations and reduction in force. On February 8, 2018, our then-current CEO, James Bennett, separated employment from the Company, and on February 22, 2018, our then-current CFO, Julian Bott, also separated employment from the Company. In accordance with the terms of their respective employment agreements, we incurred cash severance costs of $11.9 million and accelerated share-based compensation costs of $9.2 million associated with these executive terminations during the nine-month period ended September 30, ~~2017 were $49.81 per barrel~~2018 as discussed in "Note 4 - Employee Termination Benefits."

Additionally, as a result of ~~oil~~a 26% reduction in workforce in February 2018, we incurred cash severance costs of $7.6 million and ~~$3.00 per Mcf~~accelerated share-based compensation costs of ~~natural gas. Applying~~$3.9 million during the ~~actual October 1, 2017~~nine-month period ended September 30, 2018 as discussed in "Note 4 - Employee Termination Benefits."

Outlook

On June 29, 2018, the Board announced an expanded pursuit of the strategic options process with RBC Capital Markets which could have included a possible sale of the Company or significant assets of the Company. The Board also announced the beginning of a complete and ~~November 1, 2017 benchmark commodities prices,~~thorough review of assets and operating strategies, including capital expenditures and drilling programs, and expenses. On September 10, 2018, the ~~twelve-month unweighted average prices would be $50.73 per barrel~~Board announced that it had concluded its formal strategic review process following the thorough evaluation of ~~oil~~multiple potential transactions, all of which the Board believed significantly undervalued either the Company or its resources. The Board concluded that the optimal course is to develop our extensive inventory base in the NW STACK and ~~$3.01 per Mcf~~the North Park Basin and pursue value enhancement opportunities in the Mississippian Lime. We will also continue to pursue opportunistic acquisitions of ~~natural gas through November 2017.~~strategic assets that provide complimentary, high quality production and development upside in a capital disciplined manner such as the acquisition described in "—Recent Events" above. We will

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continue to focus on cost reductions, margin improvements and opportunistic divestment of core and non-core properties, while moving forward with a profitable plan for organic growth.

Consolidated Results of Operations

The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs. Our revenues, profitability and future growth depend substantially on prevailing prices received for our production, the quantity of oil, natural gas and NGLs we produce, our ability to find and economically develop and produce our reserves, and changes in the fair value of our commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict.

To provide information on the general trend in pricing, the average ~~New York Mercantile Exchange (“NYMEX”)~~NYMEX prices for oil and natural gas during the three and nine-month periods ended September 30, ~~2017,~~2018, and ~~2016~~2017 are shown in the table below:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
Oil (per Bbl)	$	69.43	$	48.20	$	66.79	$	49.36
Natural gas (per MMBtu)	$	2.86	$	2.95	$	2.85	$	3.05

Three Months Ended September 30, Nine Months Ended September 30,
2017 2016 2017 2016
Oil (per Bbl) $ 48.20
$ 44.94
$ 49.36
$ 41.53
Natural gas (per Mcf) $ 2.95
$ 2.79
$ 3.05
$ 2.35

In order to reduce our exposure to price fluctuations, we have historically entered into commodity derivative contracts for a portion of our anticipated future oil and natural gas production depending on management's view of opportunities under then-prevailing market conditions as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Reducing our exposure to price volatility helps mitigate the risk that we will not have adequate funds available for our capital expenditure programs. During periods where the strike prices for our commodity derivative contracts are below market prices at the time of settlement, we may not fully benefit from increases in the market price of oil and natural gas. Conversely, during periods of declining market prices of oil and natural gas, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement.

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Oil, Natural Gas and NGL Production and Pricing

Set forth in the table below is production and pricing information for the ~~Successor Company and the Predecessor~~ Company for the three and nine-month periods ended September 30, ~~2017,~~2018, and ~~2016.~~2017:


										Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	Successor		Predecessor		Successor		Predecessor			2018		2017		2018		2017
	2017		2016		2017		2016
Production data (in thousands)

Production data									Production data
Oil (MBbls)	954		1,282		3,130		4,315		Oil (MBbls)	956		954		2,637		3,130
NGL (MBbls)	807		1,103		2,601		3,358		NGL (MBbls)	710		807		2,110		2,601
Natural gas (MMcf)	10,850		13,079		33,883		44,124		Natural gas (MMcf)	8,757		10,850		27,221		33,883
Total volumes (MBoe)	3,569		4,565		11,378		15,027		Total volumes (MBoe)	3,126		3,569		9,284		11,378
Average daily total volumes (MBoe/d)	38.8		49.6		41.7		54.8		Average daily total volumes (MBoe/d)	34.0		38.8		34.0		41.7
Average prices—as reported(1)									Average prices—as reported(1)
Oil (per Bbl)	$	46.16	$	42.82	$	47.22	$	36.85	Oil (per Bbl)	$	66.94	$	46.16	$	63.16	$	47.22
NGL (per Bbl)	$	19.07	$	13.90	$	16.52	$	12.67	NGL (per Bbl)	$	26.45	$	19.07	$	24.70	$	16.52
Natural gas (per Mcf)	$	1.95	$	2.27	$	2.14	$	1.78	Natural gas (per Mcf)	$	1.68	$	1.95	$	1.66	$	2.14
Total (per Boe)	$	22.57	$	21.89	$	23.14	$	18.63	Total (per Boe)	$	31.19	$	22.57	$	28.41	$	23.14
Average prices—including impact of derivative contract settlements(2)
Average prices—including impact of derivative contract settlements									Average prices—including impact of derivative contract settlements
Oil (per Bbl)	$	49.67	$	53.75	$	49.42	$	51.05	Oil (per Bbl)	$	53.99	$	49.67	$	50.81	$	49.42
NGL (per Bbl)	$	19.07	$	13.90	$	16.52	$	12.67	NGL (per Bbl)	$	26.45	$	19.07	$	24.70	$	16.52
Natural gas (per Mcf)	$	2.10	$	2.32	$	2.16	$	1.77	Natural gas (per Mcf)	$	1.77	$	2.10	$	1.79	$	2.16
Total (per Boe)	$	23.97	$	25.10	$	23.81	$	22.70	Total (per Boe)	$	27.47	$	23.97	$	25.28	$	23.81

__________________


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


~~(2)~~	~~Excludes settlements of commodity derivative contracts prior to their contractual maturity.~~

1. Prices represent actual average sales prices for the periods presented and do not include effects of derivatives.

The table below presents production by area of operation for the three and ~~nine-month~~nine-month periods ended September 30, ~~2017,~~2018, and ~~2016.~~2017:


	Three Months Ended September 30,											Nine Months Ended September 30,

	2018				2017					2018					2017
	Production (MBoe)	% of Total		Production (MBoe)	% of Total		Production (MBoe)	% of Total			Production (MBoe)		% of Total

Mississippian Lime	2,414	77.2	%	3,072	86.1	%	7,482	80.5	%		9,974		87.7	%
NW STACK	221	7.1	%	242	6.8	%	743	8.0	%		537		4.7	%
North Park Basin	379	12.1	%	128	3.6	%	720	7.8	%		473		4.2	%
Permian Basin	112	3.6	%	127	3.5	%	339	3.7	%		394		3.4	%

Total	3,126	100.0	%	3,569	100.0	%	9,284	100.0	%		11,378		100.0	%

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
Production (MBoe) % of Total Production (MBoe) % of Total Production (MBoe) % of Total Production (MBoe) % of Total
Mid-Continent 3,314
92.9 % 4,250
93.1 % 10,511
92.4 % 14,119
94.0 %
North Park Basin 128
3.6 % 161
3.5 % 473
4.2 % 320
2.1 %
Permian Basin 127
3.5 % 153
3.4 % 394
3.4 % 489
3.3 %
Other —
— % 1
— % —
— % 99
0.6 %
Total 3,569
100.0 % 4,565
100.0 % 11,378
100.0 % 15,027
100.0 %

Revenues

Consolidated revenues for the ~~Successor Period~~three and ~~Predecessor Period~~nine-month periods ended September 30, 2018, and 2017 are presented in the table below (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,

	2018		2017		2018		2017
Oil	$	63,994	$	44,032	$	166,548	$	147,792
NGL	18,776		15,391		52,111		42,962
Natural gas	14,721		21,117		45,102		72,481
Other	169		352		489		858
Total revenues	$	97,660	$	80,892	$	264,250	$	264,093

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
Oil $ 44,032
$ 54,898
$ 147,792
$ 159,023
NGL 15,391
15,336
42,962
42,541
Natural gas 21,117
29,700
72,481
78,407
Other 352
4,122
858
13,838
Total revenues $ 80,892
$ 104,056
$ 264,093
$ 293,809

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Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the three and nine-month periods ended September 30, ~~2017,~~2018, and ~~2016~~2017 are shown in the tables below (in thousands):


	Three Months Ended September 30		Nine Months Ended September 30
2017 oil, natural gas and NGL revenues	$	80,540	$	263,235
Change due to production volumes	(5,831)		(45,640)
Change due to average prices	22,782		46,166
2018 oil, natural gas and NGL revenues	$	97,491	$	263,761

Three Months Ended September 30 Nine Months Ended September 30
2016 oil, natural gas and NGL revenues $ 99,934
$ 279,971
Change due to production volumes (23,280 ) (71,406 )
Change due to average prices 3,886
54,670
2017 oil, natural gas and NGL revenues $ 80,540
$ 263,235

Revenues from oil, natural gas and NGL sales ~~decreased $19.4~~increased $17.0 million, or ~~19.4%~~21.0% and $0.5 million, or 0.2% for the ~~three-month period~~three and nine-month periods ended September 30, ~~2017,~~2018, compared to the same ~~period~~periods in ~~2016, largely~~2017, respectively, due ~~to a 1.0 MMBoe decrease in total production,~~ primarily ~~due~~ to ~~natural declines in existing producing wells and fewer wells brought on production. This decrease was slightly offset by~~ an increase in average prices received for our oil and NGL ~~production. Revenues~~production during the 2018 periods. These increases were partially offset by a decrease in total production, resulting largely from ~~oil,~~ natural ~~gas and NGL sales decreased by $16.7 million, or 6.0%, for the nine-month period ended September 30, 2017, compared to the same period in 2016, primarily due to the~~ declines in production as noted above, which were largely offset by an increase in the average prices received for our oil, natural gas, and NGL production. Additionally, the average prices received for production in the 2017 periods include the effects of the Successor Company’s election to include transportation deductions in revenues for the Successor Periods as discussed below.existing producing wells.

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

Expenses

Expenses for the three and ~~nine-month~~nine-month periods ended September 30, ~~2017,~~2018, and ~~2016~~2017 consisted of the following (in thousands):


													Three Months Ended September 30,						Nine Months Ended September 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	Successor			Predecessor			Successor			Predecessor			2018		2017		2018		2017
	2017			2016			2017			2016
Production	$	26,765		$	39,640		$	76,997		$	129,608	Production	$	23,429	$	26,765	$	68,927	$	76,997
Production taxes	3,606			2,278			9,435			6,107		Production taxes	5,636		3,606		14,725		9,435
Depreciation and depletion—oil and natural gas	31,029			27,725			87,486			90,978		Depreciation and depletion—oil and natural gas	33,090		31,029		92,048		87,486
Depreciation and amortization—other	3,399			7,514			10,729			21,323		Depreciation and amortization—other	3,036		3,399		9,229		10,729
Impairment	498			354,451			3,475			718,194		Impairment	—		498		4,170		3,475
General and administrative	20,292			29,145			63,999			134,447		General and administrative	9,251		20,292		33,616		59,184
Accelerated vesting upon change in control												Accelerated vesting upon change in control	—		—		6,545		—
Proxy contest												Proxy contest	(459)		—		7,139		—
Employee termination benefits												Employee termination benefits	23		—		32,653		4,815
Loss (gain) on derivative contracts	11,702			(338		)	(46,024		)	4,823		Loss (gain) on derivative contracts	11,329		11,702		59,763		(46,024)
Loss on settlement of contract	—			—			—			90,184

Other operating (income) expense	(132		)	979			135			4,348		Other operating (income) expense	(105)		(132)		(1,343)		135
Total expenses	$	97,159		$	461,394		$	206,232		$	1,200,012	Total expenses	$	85,230	$	97,159	$	327,472	$	206,232

Production expense includes, ~~costs associated with our exploration and production activities, including,~~ but is not limited to, lease operating expense and treating costs. Production costs per Boe ~~decreased~~were relatively consistent at $7.49 for the three-month period ended September 30, 2018, compared to $7.50 for the same 2017 period. Production costs per Boe increased to $7.42 for the nine-month period ended September 30, 2018, from $6.77 per Boe for the same 2017 period, primarily due to the decrease in total production noted above.

Production taxes as a percentage of oil, natural gas and ~~$6.77~~NGL revenue increased to approximately 5.8% and 5.6% for the three and nine-month periods ended September 30, ~~2017, from $8.68 per Boe~~2018, compared to approximately 4.5% and ~~$8.63 per Boe~~3.6%, respectively, for the same ~~2016~~ periods ~~respectively,~~in 2017. These increases were primarily due to ~~(i)~~fewer wells having the ~~Successor Company’s presentation~~benefit of ~~transportation costs totaling $7.8 million and $21.5 million as a reduction from revenues for the three and nine-month periods ended September 30, 2017,~~tax credits in 2018 compared to 2017 due to the ~~Predecessor Company’s presentation~~loss of ~~transportation costs totaling $8.0 million and $26.2 million as production expenses~~certain horizontal tax credits, which caused previous rates to increase back to statutory rates for ~~the same 2016 periods, respectively, and (ii) controlled reductions in expenditures for electricity, chemicals and various other costs.~~certain wells.

Depreciation and depletion for our oil and natural gas properties increased by ~~$3.3~~$2.1 million and $4.6 million for the ~~three-month period~~three and nine-month periods ended September 30, ~~2017,~~2018, compared to the same ~~period~~periods in ~~2016,~~2017, respectively, primarily due to an increase in the average depletion ~~rate~~rates to $10.59 per Boe and $9.91 per Boe compared to $8.69 per Boe ~~compared to $6.07~~and $7.69 per Boe for the ~~2016 period.~~same 2017 periods, respectively. The ~~increase~~increases in the average depletion ~~rate~~rates resulted primarily ~~resulted~~ from ~~(i) incurring higher actual drilling and completion~~increases in future development costs ~~per Boe during the 2017 period compared to the rate per Boe calculated at December 31, 2016 following the significant ceiling test write-down incurred~~associated with proved undeveloped reserves in the ~~fourth quarter~~North Park Basin, and to a lesser extent, in our Mid-Continent NW STACK play, as well as an increase in future capital for improved recovery systems in the Mid-Continent, and to a lesser extent, the North Park Basin. As a substantial number of ~~2016, and (ii) a~~our maturing wells in the Mississippian Lime are converted or are expected to convert from submersible pump to rod pump, we anticipate an increase in capital related to rod pump production over the remaining life of such wells. As we continue to shift of more capital to develop our North Park Basin oil asset

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where the anticipated future development costs ~~likewise~~ are expected to be higher than ~~the $6.07 per Boe rate following the significant ceiling test write-down.~~ in prior periods, average depletion rates may continue to increase.

~~Depreciation and depletion for our oil and natural gas properties decreased by $3.5 million~~Impairment for the nine-month period ended September 30, ~~2017, compared~~2018, primarily reflects the write-down of midstream generator assets classified as held for sale to ~~the same period in 2016, primarily due to the decrease in production. This decrease was partially offset by an increase in the average depletion rate to $7.69 per Boe~~estimated net realizable value. Impairment for the three and nine-month ~~period~~periods ended September 30, 2017, ~~compared to $6.05 per Boe for~~reflects the same 2016 period, as noted above. Also contributing to the higher rate was a $2.9 million increase in accretion for the nine-month period ended September 30, 2017, compared to the same period in 2016, primarily due to the Successor Company recording a higher fresh start valuation for asset retirement obligations on the Emergence Date.

Depreciation and amortization - other decreased primarily due to the transfer of substantially all midstream assets to Occidental in January 2016, as well as the sale of various corporate assets during 2016 and 2017.

~~Impairment consists~~write-down of the ~~following (in thousands):~~remaining drilling and services assets classified as held for sale to estimated net realizable value.

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
Full cost pool ceiling limitation(1) $ —
$ 297,995
$ —
$ 657,392
Drilling assets(2)(3) 498
856
3,475
3,511
Electrical transmission assets(4) —
55,600
—
55,600
Midstream assets(5) —
—
—
1,691
$ 498
$ 354,451
$ 3,475
$ 718,194

~~____________________~~


~~(1)~~	Impairment recorded for the three and nine-month periods ended September 30, 2016, largely resulted from a decrease in the twelve-month weighted average oil and natural gas prices in the first half of 2016 and downward revisions to forecasted reserves due to a decrease in projected Mid-Continent production volumes in the third quarter of 2016.


~~(2)~~	Impairment for the three and nine-month periods ended September 30, 2017, reflects the write-down of remaining drilling and oilfield services assets classified as held for sale to net realizable value.


~~(3)~~	Impairment for the three and nine-month periods ended September 30, 2016, reflects the write-down of certain drilling assets after determining their future use was limited due to the Predecessor Company’s discontinued operations in the Permian region.


~~(4)~~	~~Impairment in the three and nine-month periods ended September 30, 2016, resulted from a decrease in projected Mid-Continent production volumes supporting the system’s usage.~~


~~(5)~~	~~Impairment in the nine-month period ended September 30, 2016, was recorded on compressors and various other midstream services equipment after determining that their future use was limited.~~

General and administrative expenses decreased ~~$8.9~~$11.0 million, or ~~30.4%~~54.4% for the three-month period ended September 30, ~~2017,~~2018, from the same period in ~~2016~~2017 due primarily to (i) a ~~$13.0~~$5.6 million decrease in ~~net salary~~compensation-related costs largely resulting from a reduction in force during the ~~fourth~~first quarter of ~~2016 and recording an adjustment to the 2016 retention incentive accrual in the third quarter~~2018, (ii) a decrease of ~~2016. This decrease was partially offset by (i) an increase of $2.7~~$4.2 million in professional services costs due primarily to ~~transaction~~incurring significant consultant fees in the 2017 period after the Company’s restructuring, and ~~(ii) an increase~~(iii) a decrease of ~~$1.4~~$1.2 million in other miscellaneous ~~costs.~~general and administrative items.

General and administrative expenses decreased ~~$70.4~~$25.6 million, or ~~52.4%~~43.2% for the nine-month period ended September 30, 2018, from the same period in 2017 due primarily to (i) an $18.8 million decrease in compensation-related costs largely resulting from a reduction in force during the first quarter of 2018 as well as additional declines in headcount throughout 2018, (ii) a decrease of $6.0 million in professional services costs due primarily to incurring significant consultant fees in the 2017 period after the Company’s restructuring and (iii) a decrease of $0.8 million in other miscellaneous general and administrative items.

Accelerated vesting upon change in control costs incurred during the nine-month period ended September 30, 2018 include compensation costs recognized for the accelerated vesting of certain share and incentive-based awards granted to our employees and directors as discussed in "Note 3 - Proxy Contest" in the accompanying unaudited condensed consolidated financial statements.

Proxy contest costs for the nine-month period ended September 30, 2018 include legal, consulting and advisory fees incurred in the proxy contest and strategic alternatives review which were initiated in response to shareholder actions in 2018, which were offset by a $0.5 million reimbursement of costs received in the third quarter of 2018. See "Note 3 - Proxy Contest" in the accompanying unaudited condensed consolidated financial statements for additional discussion of proxy contest costs.

Employee termination benefits for the nine-month period ended September 30, 2018, include cash and share-based severance costs incurred primarily as a result of (i) the reduction in force in the first quarter of 2018 and (ii) severance costs associated with the departure of executive officers and other senior officers. See "Note 4 - Employee Termination Benefits" in the accompanying unaudited condensed consolidated financial statements and "—Recent Events" above for additional discussion of these expenses.

Employee termination benefits for the nine-month period ended September 30, 2017, ~~from~~include cash and share-based compensation costs incurred upon the ~~same period in 2016 due primarily to (i) a $21.6 million decrease in net salary costs largely resulting from reductions in force during the first~~departure of our former Executive Vice President of Investor Relations and fourth quarters of 2016, (ii) a decrease of $20.9 million in professional services costs due to incurring significant consultant and legal fees in the 2016 period in contemplation of the Company’s restructuring, (iii) the 2016 period including the write-off of a $16.7 million joint interest account receivable due to the determination that its collection was doubtful at March 31, 2016, and (iv) a decrease of $13.5 million inStrategy, Duane Grubert as well as severance costs incurred due ~~primarily~~ to athe reduction in ~~force that occurred during~~workforce in the ~~first~~fourth quarter of 2016. ~~These decreases were partially offset by an increase~~See "Note 4 - Employee Termination Benefits" in the accompanying unaudited condensed consolidated financial statements for additional discussion of ~~$2.3~~these expenses.

We recorded losses on commodity derivative contracts of $11.3 million ~~in other miscellaneous costs.~~

and $11.7 million for the three-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $11.6 million and $(5.0) million, respectively. We recorded loss (gain) on commodity derivative contracts of ~~$11.7~~$59.8 million and $(0.3) million for the three-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $5.0 million and $14.6 million, respectively. We recorded (gain) loss on commodity derivative contracts of $(46.0) ~~million and $4.8~~ million for the nine-month periods ended September 30, ~~2017,~~2018, and ~~2016,~~2017, respectively, which include net cash ~~receipts~~payments (receipts) upon settlement of ~~$7.7~~$29.0 million and ~~$72.6~~$(7.7) million, respectively. ~~Included~~

On November 14, 2017, we entered into an Agreement and Plan of Merger (the "merger") with Bonanza Creek Energy, Inc. ("Bonanza Creek"). In contemplation of the proposed merger with Bonanza Creek, which would have been partially financed with debt, we entered into several oil derivative contracts in ~~the net cash receipts~~November 2017. We recorded losses on such oil derivatives of $6.5 million and $22.9 million for the three and nine-month ~~period~~periods ended September 30, ~~2016, are $17.9~~2018, which include net cash payments upon settlement of $2.4 million ~~of cash receipts related to early settlements.~~and $5.8 million, respectively.

Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded each quarter as a component of operating expenses. Internally, management views the settlement of commodity derivative contracts at contractual maturity as adjustments to the price received for oil and natural

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gas production to determine “effective prices.” ~~Gains or losses on early settlements and losses related to amendments of contracts, if any, are not considered in the calculation of effective prices.~~ In general, cash is received on settlement of contracts due to lower oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts, and cash is paid on settlement of contracts due to higher oil and natural gas prices at the time of settlement compared to the contract price for our commodity derivative contracts.

~~Loss on settlement of contracts for~~Other operating expense in the nine-month period ended September 30, ~~2016, includes a $78.9 million loss resulting from~~2018 primarily reflects the ~~termination~~gain on the sale of ~~a gas treating and CO~~₂ ~~delivery agreement with Occidental as well as a loss~~one of ~~$11.2 million recorded for~~ the ~~cease-use of transportation agreements that supported production from the Piñon field.~~Company’s properties located in downtown Oklahoma City, OK.

~~Other operating (income) expense primarily include drilling and oilfield services costs which largely decreased due to discontinuing all remaining drilling and oilfield services operations in 2016.~~

Other (Expense) Income

The Company’s other (expense) income for the three and ~~nine-month~~nine-month periods ended September 30, ~~2017,~~2018, and ~~2016~~2017 are presented in the table below (in thousands).


	Three Months Ended September 30,						Nine Months Ended September 30,
	2018		2017		2018		2017
Other (expense) income
Interest expense, net	$	(627)	$	(872)	$	(2,226)	$	(2,757)
Gain on extinguishment of debt	—		—		1,151		—

Other (expense) income, net	(118)		197		972		2,222
Total other expense	$	(745)	$	(675)	$	(103)	$	(535)

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
Other (expense) income
Interest expense $ (872 ) $ (3,343 ) $ (2,757 ) $ (126,099 )
Gain on extinguishment of debt —
—
—
41,179
Reorganization items —
(42,754 ) —
(243,672 )
Other income (expense), net 197
(898 ) 2,222
1,332
Total other expense $ (675 ) $ (46,995 ) $ (535 ) $ (327,260 )

~~Interest expense for the~~ ~~three and nine-month periods ended September 30, 2017, and 2016 consisted of the following (in thousands):~~

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
Interest expense, net
Interest expense on debt $ 1,255
$ 3,796
$ 3,740
$ 123,350
Amortization of debt issuance costs, discounts and premium (78 ) —
(231 ) 7,730
Gain on long-term debt holder conversion feature —
—
—
(1,324 )
Capitalized interest —
(207 ) —
(2,240 )
Total 1,177
3,589
3,509
127,516
Less: interest income (305 ) (246 ) (752 ) (1,417 )
Total interest expense, net $ 872
$ 3,343
$ 2,757
$ 126,099

~~Interest expense decreased $2.5 million and $123.3 million for the~~ ~~three and nine~~-month periods ended September 30, 2017, respectively, compared to the same periods in 2016, primarily due to the elimination of our Senior Secured Notes, Senior Unsecured Notes, and senior credit facility as part of the reorganization in 2016. The senior notes were canceled upon our emergence from Chapter 11 in the fourth quarter of 2016 and amounts outstanding under the First Lien Exit Facility were also repaid in full in the fourth quarter of 2016. There were no new borrowings on either the First Lien Exit Facility or the Credit Facility during 2017.

~~We recognized a gain~~Gain on extinguishment of debt ~~of $41.2 million~~was recognized for the nine-month period ended September 30, 2016, in connection with the exchange of certain of our Convertible Senior Unsecured Notes, including outstanding accrued interest on these notes, for shares of the Predecessor Company’s common stock.

See “Note 6 - Long-Term Debt” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of our long-term debt transactions in 2017 and 2016.

~~Reorganization items for the three-month period ended September 30, 2016, primarily consist of professional and legal~~

~~fees incurred~~2018, as a result of writing off the ~~Chapter 11 proceedings. Reorganization items for the nine-month period ended September 30, 2016 primarily consist of (i) the write-off of $148.8 million~~unamortized premium in ~~net unamortized debt premiums and discounts, unamortized debt~~

~~issuance costs and the remaining value of derivatives associated~~conjunction with the Convertible Senior Unsecured Notes and the 8.75% Senior Secured Notes due 2020 issued to Piñon Gathering Company, LLC in October 2015 that were written-off when the Bankruptcy Petitions were filed, (ii) $55.9 million in professional and legal fees incurred as a resultrepayment of the ~~Chapter 11 proceedings, (iii) an adjustment~~Building Note during the first quarter of $20.5 million for estimated allowable claims related to the Company’s legal proceedings, and (iv) $21.3 million in amounts related to the rejection or cure of certain long-term contracts as approved by the Bankruptcy Court. These items were slightly offset by approximately $6.3 million in discounts negotiated on pre-petition liabilities.2018.

Liquidity and Capital Resources

As of September 30, ~~2017,~~2018, our cash and cash equivalents, excluding restricted cash, were ~~$133.2~~$32.6 million. Additionally, we had ~~approximately $37.6 million in total~~no debt outstanding under our $425.0 million credit facility and $7.1 million in outstanding letters of credit. As of October 27, 2017, the Company had approximately $97.8 million in cash and cash equivalents, excluding restricted cash, an undrawn Credit Facility, and $7.9$6.2 million in outstanding letters of credit, which reduce the amount available under the ~~Credit Facility.~~credit facility. As of November 2, 2018, the Company had approximately $19.6 million in cash and cash equivalents, excluding restricted cash, an undrawn $350.0 million credit facility after the October 2018 redetermination, and $6.2 million in outstanding letters of credit.

Working Capital and Sources and Uses of Cash

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

Our working capital ~~surplus decreased~~deficit increased to ~~$24.2~~$98.3 million at September 30, ~~2017,~~2018, compared to ~~$43.5~~$3.8 million at December 31, ~~2016,~~2017, largely due to the ~~acquisition~~repayment of ~~oil and natural gas properties for approximately $47.7 million in cash~~the building note in the first quarter of ~~2017.~~2018, employee termination benefits paid during the first quarter of 2018 and changes in derivative assets and liabilities due to quarterly mark-to-market adjustments. This decrease is partially offset by fluctuations in the timing and amount of ~~collections of receivables and~~ payments of accounts payable and accrued ~~expenses as well as changes in derivative assets and liabilities due to quarterly mark-to-market adjustments.~~

expenses.

~~As noted in~~
~~“— Outlook,”~~ ~~in the second quarter of 2017, we increased~~

We have established a range for our ~~2017~~2018 capital expenditures budget ~~to a range~~ between ~~$250.0~~$180.0 million and ~~$260.0 million. The increase in~~$190.0 million, with the substantial majority of the budgeted ~~capital~~ expenditures ~~is offset by asset sales, continued declining production costs,~~being designated for drilling and ~~increased 2017 production expectations, lessening the impact to future liquidity.~~completion activities. Management intends to fund remaining ~~2017~~2018 capital expenditures using cash flow from operations, cash on hand and, if necessary, borrowings under the ~~Credit Facility~~credit facility discussed below.

Cash Flows

Our cash flows from operations, ~~and therefore~~which impact our ability to fund our capital expenditures, are substantially dependent on current and future prices for oil and natural gas, which historically have been, and may continue to be, volatile. For example, during the period from January ~~2015~~2016 through September ~~2017,~~2018, the ~~month-end~~ NYMEX settled price for oil fluctuated between a high of ~~$60.30~~$74.15 per Bbl in ~~May 2015~~June 2018 and a low of ~~$33.62~~$26.21 per Bbl in ~~January~~February 2016, and the month-end NYMEX settled price for gas fluctuated between a high of $3.93 per MMBtu in January 2017 and a low of $1.71 per MMBtu in March 2016.

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Our cash flows for the ~~nine-month~~nine-month periods ended September 30, ~~2017,~~2018, and ~~2016~~2017 are presented in the following table and discussed below (in thousands):


	Nine Months Ended September 30,
	2018		2017
Cash flows provided by operating activities	$	109,168	$	147,906
Cash flows used in investing activities	(132,322)		(181,210)
Cash flows used in financing activities	(43,680)		(5,254)
Net decrease in cash and cash equivalents	$	(66,834)	$	(38,558)

Nine Months Ended September 30,
Successor Predecessor
2017 2016
Cash flows provided by (used in) operating activities $ 147,906
$ (64,039 )
Cash flows used in investing activities (181,210 ) (167,690 )
Cash flows (used in) provided by financing activities (5,254 ) 448,821
Net (decrease) increase in cash and cash equivalents $ (38,558 ) $ 217,092

Cash Flows from Operating Activities

The ~~$211.9~~$38.7 million ~~increase~~decrease in operating cash flows for the nine-month period ended September 30, ~~2017,~~2018, compared to the same period in ~~2016,~~2017, is primarily due to (i) ~~a reduction in~~ cash paid for ~~interest expense,~~employee termination benefits, (ii) ~~a reduction~~cash paid on settlement of derivative contracts in the 2018 period compared to receiving cash in the 2017 period, and (iii) other changes in working capital, partially offset by lower general and administrative expenses, (iii) a reduction in production expenses, and (iv) cash payments made in the 2016 period to certain holders of the Convertible Notes who elected to convert their notes into shares of the Predecessor Company’s stock. These increases were partially offset by a decrease in cash received for the settlement of derivatives.costs. See “—Consolidated Results of Operations” for further analysis of the changes in operating expenses.

Cash Flows from Investing Activities

~~The Company dedicates~~We dedicate and ~~expects~~expect to continue to dedicate a substantial portion of ~~its~~our capital expenditure program toward the exploration for and ~~production~~development of our oil and natural ~~gas.~~gas properties. These capital expenditures are necessary to offset inherent declines in production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. During the ~~nine-month~~nine-month period ended September 30, 2018, cash flows used in investing activities primarily consisted of capital expenditures for drilling and completion activities, which were partially offset by proceeds received from the sale of one of the Company's properties located in downtown Oklahoma City and various other midstream equipment. During the nine-month period ended September 30, 2017, cash flows used in investing activities included the acquisition of 13,000 net acres in Woodward County, Oklahoma for approximately ~~$47.7~~$47.8 million in cash and capital expenditures for ~~exploration~~drilling and ~~production,~~completion activities, which were partially offset by proceeds of $19.8 million from the sale of various non-core oil and natural gas properties and certain drilling equipment previously classified as held for sale. During the nine-month period ended September 30, 2016, cash flows used in investing activities primarily consisted of capital expenditures for exploration and production activities, which were slightly offset by proceeds from the sale of various non-core oil and natural gas properties.

Capital expenditures ~~on an accrual basis~~ for the nine-month periods ended September 30, ~~2017,~~2018, and ~~2016~~2017 are summarized on an accrual basis below (in thousands):

Nine Months Ended September 30,
Successor Predecessor
2017 2016
Capital Expenditures (on an accrual basis)
Exploration and production $ 166,296
$ 155,627
Other - operating 282
3,108
Other - corporate 1,406
2,672
Capital expenditures, excluding acquisitions 167,984
161,407
Acquisitions 48,236
1,328
Total $ 216,220
$ 162,735


	Nine Months Ended September 30,
	2018		2017
Capital Expenditures (on an accrual basis)
Drilling and completion	$	107,382	$	122,438
Leasehold and geophysical	9,842		43,858
Other - operating	410		282
Other - corporate	44		1,406
Capital expenditures, excluding acquisitions	117,678		167,984
Acquisitions	—		48,236
Total	$	117,678	$	216,220

Capital expenditures, excluding acquisitions, for exploration and production activities increased in the 2017 period compared to the 2016 period due primarily to an increase in drilling activity in the third quarter of 2017.

Cash Flows from Financing Activities

Our cash used in financing activities was approximately $43.7 million for the nine-month period ended September 30, 2018, which consisted of the repayment of the building note and cash paid for employee tax obligations in connection with the withholding of common shares upon vesting of employee share-based compensation awards. Our cash used in financing activities was approximately $5.3 million ~~of cash for~~during the nine-month period ended September 30, 2017, which consisted of cash paid for employee tax obligations in connection with the ~~purchase~~withholding of common ~~stock~~shares upon ~~the~~ vesting of employee share-based compensation awards and deferred financing costs incurred on the ~~Credit Facility. Our financing activities provided approximately $448.8 million during the nine-month period ended September 30, 2016, primarily due to net borrowings under the senior~~ credit ~~facility in the first quarter~~facility.

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Indebtedness

Credit Facility

~~Long-term~~

We had no debt ~~consists of the following~~outstanding under our credit facility at September 30, ~~2017 (in thousands):~~

Credit Facility $ —
Building Note 37,601
Total Debt $ 37,601

~~Credit Facility~~

~~On February 10, 2017, the First Lien Exit Facility was refinanced into a new $600.0 million Credit Facility with a $425.0 million borrowing base.~~2018. The ~~Credit Facility agreement had the following impacts:~~

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

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

~~borrowing base determinations now include our proportionately consolidated share of proved reserves held by the Royalty Trusts;~~

reduced the interest rate from a flat base rate of LIBOR plus 4.75% per annum to a pricing grid tied to borrowing base utilization of (A) LIBOR plus an applicable margin that varies from 3.00% to 4.00% per annum, or (B) the base rate plus an applicable margin that varies from 2.00% to 3.00% per annum;

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

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

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

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

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

~~The initial~~ borrowing base under the ~~Credit Facility was $425.0~~credit facility is $350.0 million, which was ~~reconfirmed in~~reduced from $425.0 million during the October ~~2017~~2018 borrowing base redetermination. The next semi-annual borrowing base redetermination is scheduled for April 1, ~~2018.~~2019. The ~~Credit Facility~~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~~our most recently delivered reserve report, ~~of the Company,~~ (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing). ~~As described above, the Credit Facility refinanced and thereby replaced the First Lien Exit Facility.~~

~~Beginning with the quarter ended June 30, 2017, the Credit Facility~~The credit facility requires ~~the Company~~us to maintain (i) a maximum consolidated total net leverage ratio, measured as of the end of any fiscal quarter, of no greater than 3.50 to 1.00 and (ii) a minimum consolidated interest coverage ratio, measured as of the end of any fiscal quarter, of no less than 2.25 to 1.00. These financial covenants are subject to customary cure rights. ~~The Company was~~We were in compliance with all applicable financial covenants under the ~~Credit Facility~~credit facility as of September 30, ~~2017.~~2018.

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

Building Note

On the Emergence Date, ~~the Company~~we entered into the Building Note, which had an initial principal amount of $35.0 million and iswas secured by first priority mortgages on ~~the Company’s~~our real estate in Oklahoma City, Oklahoma. We repaid the Building Note in full during February 2018. The Building Note was recorded at fair value ($36.6 million) upon implementation of fresh start ~~accounting. 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,~~accounting, and ~~10% thereafter through maturity. Interest on the Building Note was initially payable in kind. Approximately~~approximately $1.3 million in in-kind interest costs were added to the ~~Building Note~~ principal ~~from the Emergence Date through May 11, 2017, which was 90 days~~prior to interest becoming payable in cash after the refinancing of the First Lien Exit Facility. ~~Interest became payable thereafter in cash.~~ The Building Note ~~matures~~was set to mature on October 2, 2021, and ~~became~~was prepayable in whole or in part without premium or ~~penalty upon the refinancing of the First Lien Exit Facility.~~penalty.

See “Note 69 - Long-Term Debt” to the accompanying unaudited condensed consolidated financial statements for additional discussion of the Company’s debt.

Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, ~~2016,~~2017, the Company’s contractual obligations included long-term debt obligations, third-party drilling rig agreements, asset retirement obligations, operating leases and other individually insignificant obligations. Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including standby letters of credit and surety bonds. The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds.

Other than the ~~conversion~~repayment of the ~~Convertible Notes~~Building Note discussed in “—Overview,” and the drilling participation agreement discussed in “—Overview” and “Note 2 - Recent Transactions” to the accompanying unaudited condensed consolidated financial statements,above, there were no other significant changes in contractual obligations and off-balance sheet arrangements from those reported in the ~~2016~~2017 Form 10-K.

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Critical Accounting Policies and Estimates

For a description of our critical accounting policies and estimates, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the ~~2016~~2017 Form 10-K. For a discussion of recent accounting pronouncements, newly adopted and recent accounting pronouncements not yet adopted, see “Note 1 - Basis of Presentation” to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report. We did not have any material changes in critical accounting policies, estimates, judgments and assumptions during the first nine months of ~~2017.~~2018.

~~Valuation Allowance~~

Upon emergence from bankruptcy and the application of fresh start accounting, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had a significant U.S. Federal NOL carryforward remaining after the attribute reduction caused by the restructuring transactions. As such, the Successor Company had significant deferred tax assets to consume upon emergence. We considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be realized and established a valuation allowance against our net deferred tax asset upon emergence and maintained the valuation allowance for the subsequent periods through September 30, 2017.

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

In determining whether to maintain the valuation allowance at September 30, 2017, we concluded that the objectively verifiable negative evidence of the presumption of cumulative negative earnings upon emergence and actual cumulative negative earnings for the Successor Company period ended September 30, 2017, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, we have not changed our judgment regarding the need for a full valuation allowance against our net deferred tax asset for the period ended September 30, 2017.

~~See “Note 10 - Income Taxes” to the accompanying unaudited condensed consolidated financial statements for additional discussion of income tax related matters.~~

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General

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

Commodity Price ~~Risk.~~Risk. Our most significant market risk relates to the prices we receive for our oil, natural gas and NGLs. Due to the historical price volatility of these commodities, from time to time, depending upon our view of opportunities under the then-prevailing current market conditions, we enter into commodity price derivative contracts for a portion of our anticipated production volumes for the purpose of reducing variability of oil and natural gas prices we receive. Our ~~Credit Facility~~credit facility limits our ability to enter into derivative transactions to 90% of expected production volumes from estimated proved ~~reserves.~~reserves over the period covered by the transactions.

We use, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At September 30, ~~2017,~~2018, our commodity derivative contracts consisted of fixed price swaps under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.

Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.

On June 26, 2018, the Board suspended the Company's ability to enter into new commodity derivative contracts pending review. In November 2018, the Board concluded this comprehensive evaluation of its commodity derivatives program and determined that no action should be taken with respect to outstanding derivatives contracts at this time. Future derivative transactions will require Board approval.

At September 30, ~~2017~~,2018, our open commodity derivative contracts consisted of the following:

Oil Price Swaps


	Notional (MBbls)	Weighted Average Fixed Price
October 2018 - December 2018	828	$	56.12
January 2019 - December 2019	1,825	$	54.29

Notional (MBbls)
Weighted Average
Fixed Price
October 2017 - December 2017 828
$ 52.24
January 2018 - December 2018 2,006
$ 54.87

Natural Gas Price Swaps


	Notional (MMcf)	Weighted Average Fixed Price
October 2018 - December 2018	3,680	$	3.11

Notional (MMcf)
Weighted Average
Fixed Price
October 2017 - December 2017 8,280
$ 3.20
January 2018 - December 2018 17,300
$ 3.16

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

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The Company recorded losses on commodity derivative contracts of $11.3 million and $11.7 million for the three-month periods ended September 30, 2018, and 2017, respectively, which include net cash payments (receipts) upon settlement of $11.6 million and $(5.0) million, respectively. We recorded loss (gain) on commodity derivative contracts of ~~$11.7~~$59.8 million and $(0.3) million for the three-month periods ended September 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $5.0 million and $14.6 million, respectively. We recorded (gain) loss on commodity derivative contracts of $(46.0) ~~million and $4.8~~ million for the nine-month periods ended September 30, ~~2017,~~2018, and ~~2016,~~2017, respectively, which include net cash ~~receipts~~payments (receipts) upon settlement of ~~$7.7~~$29.0 million and ~~$72.6~~$(7.7) million, respectively. ~~Included in the net cash receipts for the nine-month period ended September 30, 2016, are $17.9 million of cash receipts related to early settlements.~~

See “Note 710 - Derivatives” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding our commodity derivatives.

Credit Risk. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating. We monitor the

credit ratings of our derivative counterparties and consider our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. Our derivative contracts are with multiple counterparties to minimize exposure to any individual counterparty.

We do not require collateral or other security from counterparties to support derivative instruments. We have master netting agreements with each of our derivative contract counterparties, which allow us to net our derivative assets and liabilities by commodity type with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender under the ~~Credit Facility~~credit facility can be offset against amounts owed, if any, to such counterparty. As of September 30, ~~2017,~~2018, the counterparties to our open commodity derivative contracts consisted of ~~seven~~five financial institutions, all of which are also lenders under our ~~Credit Facility.~~credit facility. As a result, we are not required to post additional collateral under our commodity derivative contracts.

Interest Rate Risk. We are exposed to interest rate risk on our ~~Credit Facility.~~credit facility. This variable interest rate on our ~~Credit Facility~~credit facility fluctuates, and exposes us to short-term changes in market interest rates as our interest obligations on this instrument is periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate. We had no outstanding variable rate debt as of September 30, ~~2017.~~2018.

ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

Under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15 as of the end of the period covered by this Quarterly Report. Based on that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, ~~2017,~~2018, to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There was no change in the Company’s internal control over financial reporting during the quarter ended September 30, ~~2017,~~2018 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. Other Information

ITEM 1. Legal Proceedings

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. On August 13, 2018, the court granted the Company’s motion to dismiss, thereby dismissing the Company from the lawsuit.

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

Pursuant to the Plan, claims against the Company were discharged without recovery in each of the following consolidated Cases:

• In re SandRidge Energy, Inc. Securities Litigation, Case No. 5:12-cv-01341-LRW, USDC, Western District of Oklahoma

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

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

ITEM 1A. Risk Factors

~~There~~Except as set forth below, there have been no material changes to the risk factors previously discussed in Item 1A—Risk Factors in the ~~Company’s 2016~~Company's 2017 Form 10-K.

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

The Company has substantial undeveloped reserves and unproved acreage in the North Park Basin area of Jackson County, Colorado. Recently, various initiatives have been promoted by interest groups in Colorado to increase regulations restricting oil and gas development. For example, on November 6, 2018, Coloradans considered Proposition 112, a ballot initiative that would have established a new statewide minimum distance requirement for new oil and gas development far in excess of existing Colorado Oil and Gas Conservation Commission (“COGCC”) setback regulations. Although Coloradans did not approve Proposition 112, future similar initiatives, if implemented, could pose operational challenges, substantially limit our development activity and require higher levels of capital expenditures than we currently anticipate, and therefore have a significant adverse effect on our ability to develop proved undeveloped reserves in the North Park Basin. Even if we are able to develop these assets, delayed development of our reserves or increases in costs to drill and develop such reserves will reduce

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the present value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves. Such restrictions, additional costs and delays could adversely impact our financial condition, results of operations and/or cash flows.

Risks and uncertainties related to the potential sale or lease of our corporate headquarters.

The Company's corporate headquarters building in downtown Oklahoma City, OK, is substantially underutilized. The Company has entered into a brokerage agreement to seek to lease the unutilized portion of the building. The Company is also currently considering offers to purchase the entire building. Any alternative we pursue is subject to certain risks and uncertainties, including, among other things, the possibility that any alternative we select will not be completed on terms that are advantageous to us and the possibility that an outright sale of our corporate headquarters will be at a sales price significantly below its current carrying value on our books.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

~~The following table presents a summary of~~There were no share repurchases made by the Company during the three-month period ended September 30, ~~2017~~2018.

Period Total Number of Shares Purchased(1) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Program Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in Millions)
July 1, 2017 — July 31, 2017 44,999
$ 19.44
N/A
N/A
August 1, 2017 — August 31, 2017 —
$ —
N/A
N/A
September 1, 2017 — September 30, 2017 —
$ —
N/A
N/A
Total 44,999
—

~~____________________~~


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

ITEM 3. Defaults upon Senior Securities

None.

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ITEM 6. Exhibits

~~See the Exhibit Index accompanying this Quarterly Report.~~

Incorporated by Reference

Exhibit

No.

Exhibit Description

Form

SEC

File No.

Exhibit

Filing Date

Filed

Herewith

2.1

Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc., et al., dated September 19, 2016

8-A

001-33784

2.1

10/4/2016

3.1

Amended and Restated Certificate of Incorporation of SandRidge Energy, Inc.

8-A

001-33784

3.1

10/4/2016

3.2

Amended and Restated Bylaws of SandRidge Energy, Inc.

8-A

001-33784

3.2

10/4/2016

10.1†

Amended and Restated SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated August 8, 2018

10.1.1†

Form of Non-employee Director Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated July 17, 2018

10.1.2†

Form of Executive Restricted Stock Award Agreement for Amended and Restated SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated August 9, 2018

10.1.3†

Form of Performance Share Unit Award Agreement for Amended and Restated SandRidge Energy, Inc. 2016 Omnibus Incentive Plan, dated September 5, 2018

31.1

S ection 302 Certification—Chief Executive Officer

31.2

Section 302 Certification—Chief Financial Officer

32.1

Section 906 Certifications of Chief Executive Officer and Chief Financial Officer

101.INS

XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH

XBRL Taxonomy Extension Schema Document

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF

XBRL Taxonomy Extension Definition Document

101.LAB

XBRL Taxonomy Extension Label Linkbase Document

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

† Management contract or compensatory plan or arrangement

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	SandRidge Energy, Inc.

	~~SandRidge Energy, Inc.~~

By:		/s/ ~~Julian Bott~~Michael A. Johnson
			~~Julian Bott~~Michael A. Johnson ~~Executive~~Senior Vice President and Chief Financial Officer

Date: November ~~3, 2017~~8, 2018

~~EXHIBIT INDEX~~

Incorporated by Reference
Exhibit
No.
Exhibit Description Form
SEC
File No.
Exhibit Filing Date
Filed
Herewith
2.1
Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc., et al., dated September 19, 2016

8-A 001-33784 2.1 10/4/2016
3.1
Amended and Restated Certificate of Incorporation of SandRidge Energy, Inc.

8-A 001-33784 3.1 10/4/2016
3.2
Amended and Restated Bylaws of SandRidge Energy, Inc.

8-A 001-33784 3.2 10/4/2016
10.1.1.1†

Form of Amendment No. 1 to the Non-employee Director Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan

*

10.1.2.1†

Form of Amendment No. 1 to the Executive Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan

*

10.1.4.1†

Form of Amendment No. 1 to the Restricted Stock Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan

*

10.1.6.1†
Form of Amendment No. 1 to the Non-employee Director Restricted Stock Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan

*
31.1
Section 302 Certification—Chief Executive Officer
*
31.2
Section 302 Certification—Chief Financial Officer
*
32.1
Section 906 Certifications of Chief Executive Officer and Chief Financial Officer
*
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. *
101.SCH XBRL Taxonomy Extension Schema Document *
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document             *
101.DEF XBRL Taxonomy Extension Definition Document             *
101.LAB XBRL Taxonomy Extension Label Linkbase Document             *
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document             *



	September 30, 2017			December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	133,201		$	121,231
Restricted cash - collateral	—			50,000
Restricted cash - other	2,312			2,840
Accounts receivable, net	69,187			74,097
Derivative contracts	6,608			—
Prepaid expenses	2,334			5,375
Other current assets	8,045			3,633
Total current assets	221,687			257,176
Oil and natural gas properties, using full cost method of accounting
Proved	1,004,370			840,201
Unproved	103,533			74,937
Less: accumulated depreciation, depletion and impairment	(432,564		)	(353,030		)
	675,339			562,108
Other property, plant and equipment, net	238,420			255,824
Derivative contracts	2,010			—
Other assets	1,327			6,284
Total assets	$	1,138,783		$	1,081,392



	Nine Months Ended September 30, 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 balance	$	—



	September 30, 2017				December 31, 2016
	Fair Value		Carrying Value		Fair Value		Carrying Value
Convertible Notes	$	—	$	—	$	334,800	$	268,780
Building Note	$	41,638	$	37,601	$	40,608	$	36,528



	Number of Shares		Weighted-Average Grant Date Fair Value
	(In thousands)
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85
Granted	—		$	—
Vested	(3,034	)	$	5.34
Forfeited / Canceled	(158	)	$	6.25
Unvested restricted shares outstanding at September 30, 2016	2,434		$	4.15



	Three Months Ended September 30			Nine Months Ended September 30
2016 oil, natural gas and NGL revenues	$	99,934		$	279,971
Change due to production volumes	(23,280		)	(71,406		)
Change due to average prices	3,886			54,670
2017 oil, natural gas and NGL revenues	$	80,540		$	263,235



Period	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in Millions)
July 1, 2017 — July 31, 2017	44,999	$	19.44	N/A	N/A
August 1, 2017 — August 31, 2017	—	$	—	N/A	N/A
September 1, 2017 — September 30, 2017	—	$	—	N/A	N/A
Total	44,999			—



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
2.1	Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc., et al., dated September 19, 2016	8-A	001-33784	2.1	10/4/2016
3.1	Amended and Restated Certificate of Incorporation of SandRidge Energy, Inc.	8-A	001-33784	3.1	10/4/2016
3.2	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-A	001-33784	3.2	10/4/2016
10.1.1.1†	Form of Amendment No. 1 to the Non-employee Director Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.1.2.1†	Form of Amendment No. 1 to the Executive Emergence Restricted Stock Award Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.1.4.1†	Form of Amendment No. 1 to the Restricted Stock Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
10.1.6.1†	Form of Amendment No. 1 to the Non-employee Director Restricted Stock Award Certificate and Agreement for SandRidge Energy, Inc. 2016 Omnibus Incentive Plan					*
31.1	Section 302 Certification—Chief Executive Officer					*
31.2	Section 302 Certification—Chief Financial Officer					*
32.1	Section 906 Certifications of Chief Executive Officer and Chief Financial Officer					*
101.INS	XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.					*
101.SCH	XBRL Taxonomy Extension Schema Document					*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document					*
101.DEF	XBRL Taxonomy Extension Definition Document					*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document					*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document					*

Notional (MBbls)

Weighted Average
Fixed Price

October 2017 - December 2017

January 2018 - December 2018