SECURITIES AND EXCHANGE COMMISSION

~~__________________________~~

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma

Registrant’s telephone number, including area code:

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

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Trading Symbol

Name of Each Exchange on Which Registered

Common Stock, $0.001 par value

New York Stock Exchange

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,~~May 2, 2019, was ~~35,647,066.~~

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 and SandRidge Mississippian Trust II for periods ending March 31, 2019 and December 31, 2018 and SandRidge Permian Trust for the period ending March 31, 2018 (collectively, the “Royalty Trusts”).

This Quarterly Report on Form 10-Q (“Quarterly Report”) of the Company includes “forward-looking statements” ~~within~~as defined by 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.SEC. These forward-looking statements may include projections and estimates concerning ~~the Company’s~~our capital expenditures, liquidity, capital resources and debt profile, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of ~~the Company’s~~our business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the potential effects ~~thereof~~ on ~~the Company’s~~our financial condition and other statements concerning ~~the Company’s~~our operations, ~~and~~ financial performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. ~~The Company has based these~~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~~based on our experience and perception of historical trends, current conditions and expected future developments as well as other factors ~~the Company believes~~we believe 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.~~projected. 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~~we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in “Risk Factors” in Item 1A of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2016~~2018 (the ~~“2016~~“2018 Form 10-K”) and in Item 1A of this Quarterly Report.

ITEM 1. Financial Statements

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

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


	Three Months Ended March 31,
	2019		2018
Revenues
Oil, natural gas and NGL	$	73,048	$	86,966
Other	188		162
Total revenues	73,236		87,128
Expenses
Lease operating expenses	22,779		23,519
Production, ad valorem, and other taxes	5,080		6,234
Depreciation and depletion — oil and natural gas	36,465		27,997
Depreciation and amortization — other	2,943		3,153
Impairment	—		4,170
General and administrative	9,939		13,682

Proxy contest	—		407
Employee termination benefits	—		31,587
Loss on derivative contracts	209		18,330

Other operating expense	82		16
Total expenses	77,497		129,095
Loss from operations	(4,261)		(41,967)
Other (expense) income
Interest expense, net	(585)		(948)
Gain on extinguishment of debt	—		1,151

Other (expense) income, net	(431)		873
Total other (expense) income	(1,016)		1,076
Loss before income taxes	(5,277)		(40,891)
Income tax expense	—		3
Net loss	$	(5,277)	$	(40,894)


Loss per share
Basic	$	(0.15)	$	(1.18)
Diluted	$	(0.15)	$	(1.18)
Weighted average number of common shares outstanding
Basic	35,322		34,575
Diluted	35,322		34,575

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

~~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
Three Months Ended March 31, 2019
Balance at December 31, 2018	35,687	$	36	6,604	$	88,516	$	1,055,164	$	(295,995)	$	847,721



Stock-based compensation	—	—		—	—		1,073		—		1,073
Issuance of warrants for general unsecured claims	—	—		1	2		(2)		—		—
Cumulative effect of adoption of ASU 2016-02	—	—		—	—		—		(57)		(57)
Net loss	—	—		—	—		—		(5,277)		(5,277)
Balance at March 31, 2019	35,687	$	36	6,605	$	88,518	$	1,056,235	$	(301,329)	$	843,460

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


	Common Stock				Warrants				Additional Paid-In Capital				Accumulated Deficit	Total
	Shares	Amount		Shares	Amount
Three Months Ended March 31, 2018
Balance at December 31, 2017	35,650	$	36	6,570	$	88,500	$	1,038,324	$	(286,920)	$	839,940
Cancellation of stock awards, net of issuances	(90)	—		—	—		—		—		—


Stock-based compensation	—	—		—	—		16,055		—		16,055

Cash paid for tax withholdings on vested stock awards	—	—		—	—		(1,661)		—		(1,661)
Net loss	—	—		—	—		—		(40,894)		(40,894)
Balance at March 31, 2018	35,560	$	36	6,570	$	88,500	$	1,052,718	$	(327,814)	$	813,440

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

Table of Contents

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)


	Nine Months Ended September 30,
	Successor			Predecessor				Three Months Ended March 31,
	2017			2016				2019		2018
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							Net loss	$	(5,277)	$	(40,894)
Adjustments to reconcile net loss to net cash provided by operating activities							Adjustments to reconcile net loss to net cash provided by operating activities
Provision for doubtful accounts	133			16,704			Provision for doubtful accounts	72		(335)
Depreciation, depletion and amortization	98,215			112,301
Depreciation, depletion, and amortization							Depreciation, depletion, and amortization	39,408		31,150
Impairment	3,475			718,194			Impairment	—		4,170
Reorganization items, net	—			231,836

Debt issuance costs amortization	313			4,996			Debt issuance costs amortization	117		117
Amortization of premiums and discounts on debt	(231		)	2,734			Amortization of premiums and discounts on debt	—		(47)
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 on derivative contracts							Loss on derivative contracts	209		18,330
Cash received (paid) on settlement of derivative contracts							Cash received (paid) on settlement of derivative contracts	5,078		(6,119)

Stock-based compensation	12,616			9,075			Stock-based compensation	996		15,872
Other	188			(3,260		)	Other	(35)		(235)
Changes in operating assets and liabilities	5,699			(3,805		)	Changes in operating assets and liabilities	(8,998)		9,549
Net cash provided by (used in) operating activities	147,906			(64,039		)
Net cash provided by operating activities							Net cash provided by operating activities	31,570		30,407
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	(62,254)		(65,527)
Acquisition of assets	(48,236		)	(1,328		)	Acquisition of assets	326		—
Proceeds from sale of assets	19,769			20,090			Proceeds from sale of assets	341		955
Net cash used in investing activities	(181,210		)	(167,690		)	Net cash used in investing activities	(61,587)		(64,572)
CASH FLOWS FROM FINANCING ACTIVITIES							CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	—			489,198			Proceeds from borrowings	39,596		—
Repayments of borrowings	—			(40,000		)	Repayments of borrowings	(19,596)		(36,304)
Debt issuance costs	(1,488		)	(333		)
Reduction of financing lease liability							Reduction of financing lease liability	(293)		—

Cash paid for tax withholdings on vested stock awards	(3,766		)	(44		)	Cash paid for tax withholdings on vested stock awards	—		(1,661)
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 provided by (used in) financing activities							Net cash provided by (used in) financing activities	19,707		(37,965)
NET DECREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH							NET DECREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH	(10,310)		(72,130)
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	174,071			435,588			CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	19,645		101,308
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period	$	135,513		$	652,680		CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period	$	9,335	$	29,178
Supplemental Disclosure of Cash Flow Information							Supplemental Disclosure of Cash Flow Information
Cash paid for reorganization items	$	—		$	(11,836	)
Cash paid for interest, net of amounts capitalized							Cash paid for interest, net of amounts capitalized	$	(408)	$	—
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	$	(9,190)	$	28,258
Equity issued for debt	$	(268,779	)	$	(4,409	)
Right-of-use assets obtained in exchange for financing lease obligations							Right-of-use assets obtained in exchange for financing lease obligations	$	1,992	$	—

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~~acquisition, exploration and ~~North Park Basin~~development 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”)hydrocarbon resources 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”).

States.

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 and notes as of December 31, ~~2016,~~2018 have been derived from 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~~2018 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~~2018 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.

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

2. Leases

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” and subsequently issued other associated ASU's related to Topic 842 which supersede ASC 840 and require lessees to recognize right of use ("ROU") lease assets and liabilities on the balance sheet for long-term leases formerly classified as operating leases under ASC 840, and to disclose key information about leasing arrangements. Leases to explore for or produce oil and natural gas were not impacted by this guidance. This ASU became effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The Company adopted this ASU on January 1, 2019 using a modified retrospective approach for all ROU leases that existed at the period of adoption and did not restate its comparative periods.

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~~Topic 842 provides a number of ~~Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments”~~practical expedients to assist with the ~~objective~~transition to the new standard. The Company elected the 'package of ~~reducing~~practical expedients,' and therefore did not have to reassess prior conclusions about lease identification, lease classification and initial indirect costs. The Company also utilized the ~~existing diversity in practice of classification~~land easement practical expedient and short-term lease recognition exemption, under which leases with initial terms less than 12 months are not required to be presented on ~~certain cash receipts~~the balance sheet. Certain leases contain both lease and ~~payments in~~non-lease components. The Company elected the ~~statement of cash flows.~~ practical expedient to combine lease and non-lease components for asset classes including drilling rigs, compressors and various office equipment.

The ~~guidance requires adoption by application~~Company determines if an arrangement is or contains a lease at inception. A lease is defined as a contract, or part of a ~~retrospective method~~contract, that conveys the right to ~~each~~control the use of identified property, plant or equipment for a period ~~presented.~~of time in exchange for consideration. Lease liabilities are recognized based on the present value of the lease payments not yet paid over the lease term at January 1, 2019 for existing leases and at the commencement date for any new leases entered into subsequent to January 1, 2019. As most of the Company's leases do not provide an implicit rate, the Company's incremental borrowing rate was used as the discount rate when determining the present value of future payments. The ~~amendments~~ROU assets are ~~effective~~recognized based on the lease liability plus any prepaid lease payments and excluding lease incentives and initial direct costs incurred for the ~~Company~~same periods. The Company's lease terms may include options to extend or terminate the lease when it is reasonably certain that option will be exercised. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

Adoption of this standard resulted in additional ROU lease assets and lease liabilities of approximately $2.3 million and $2.4 million, respectively, as of January 1, ~~2018, with early adoption permitted.~~2019, which did not materially impact the Company's consolidated financial statements. The difference between the net lease assets and liabilities was recognized as a cumulative-effect adjustment to the opening balance of retained earnings. Operating leases are included in other assets and other long-term obligations, and finance leases are included in other property, plant and equipment, and other long-term obligations on the accompanying condensed consolidated balance sheet as of March 31, 2019. The Company ~~adopted the ASU on April 1, 2017. The guidance~~ had no ~~impact on~~significant capital or operating leases with terms longer than 12 months at December 31, 2018.

The Company has operating and financing leases for vehicles, drilling rigs and equipment, which are not significant to the consolidated financial statements as of and ~~related disclosures.~~for the three-month period ended March 31, 2019.

The ~~FASB Issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition~~components 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~~lease costs recognized 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 ASUCompany's ROU leases 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.

shown below:


	Three Months Ended March 31, 2019
Short-term lease cost (1)	$	4,909
Financing lease cost	297
Operating lease cost	58
Total lease cost	$	5,264

____________________

1.~~Recent Accounting Pronouncements Not Yet Adopted.~~$3.1 million The FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” 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~~short-term lease cost was capitalized as part of revenues. In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which defers the effective date of ASU 2014-09 to January 1, 2018, for the Company, with early adoption permitted in 2017. The ASU must be adopted using either the retrospective transition method, which requires restating previously reported results or the cumulative effect (modified retrospective) transition method, which utilizes a cumulative-effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company plans to adopt the ASU on January 1, 2018, using the modified retrospective transition method.

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

The Company 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~~properties, and portions of ~~a modified retrospective transition approach for existing long-term leases and is effective for~~these costs were reimbursed to 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.by other working interest owners.

The FASB issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other than Inventory” which removes the prohibition in Accounting Standards Codification (“ASC”) 740 against the immediate recognition of current and deferred income tax effects of intra-entity transfers of assets other than inventory. The amendments in this ASU are effective for the Company on January 1, 2018, with early adoption permitted on January 1, 2017. The ASU should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Company plans to adopt the ASU on January 1, 2018 and continues to evaluate the effect that the guidance will have on its consolidated financial statements.

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3. Employee Termination Benefits

No employee termination benefits were paid during the three-month period ended March 31, 2019. The ~~FASB issued ASU 2017-05, “Other Income - Gains and Losses~~following table presents a summary of employee termination benefits for the three-month period ended March 31, 2018 which occurred before the change in composition of the current Board of Directors (in thousands):


	Cash		Share-Based Compensation (3)		Number of Shares	Total Employee Termination Benefits












Three Months Ended March 31, 2018
Executive Employee Termination Benefits (1)	$	11,945	$	9,114	554	$	21,059
Other Employee Termination Benefits (2)	6,692		3,836		209	10,528
	$	18,637	$	12,950	763	$	31,587

____________________

1.On February 8, 2018, the Company’s then current chief executive officer ("CEO"), James Bennett, separated employment from the ~~Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying~~Company, and on February 22, 2018, the ~~Scope of Asset Derecognition Guidance and~~Company’s then current chief financial officer ("CFO"), Julian Bott, also separated employment from the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarify that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company plans to adopt the ASU on January 1, 2018, using the modified retrospective transition method. The Company continues to evaluate the effect that the updated standard will have on its consolidated financial statements and related disclosures.

~~2. Recent Transactions~~

In the third quarter of 2017, the Company entered into a $200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of its undeveloped leasehold acreage within the Meramec formation in Major and Woodward Counties in Oklahoma (the “NW STACK”). Under this agreement, the Counterparty is paying 90% of the net exploration and development costs, up to $100.0 million in the first tranche, in exchange for an initial 80% net working interest in each new well, subject to certain reversionary hurdles, as shown in the table below.Company. As a result, the Company ~~is receiving~~paid cash severance costs and incurred share-based compensation costs associated with these separations during the first quarter of 2018.

2.As a ~~20% net working interest after funding 10%~~result of a reduction in workforce in the first quarter of 2018, certain employees received termination benefits including cash severance and accelerated share-based and incentive compensation upon separation of service from the Company.

3.Share-based compensation recognized in connection with the accelerated vesting of restricted stock awards and performance share units upon the departure of certain executives and the reduction in workforce in the first quarter of 2018 reflects the remaining unrecognized compensation expense associated with these awards at the date of termination. The unrecognized compensation expense was calculated using the grant date fair value for restricted stock awards and performance share units. One share of the ~~exploration and development costs related to the subject wells. This will allow the Company to spend minimal~~Company’s common stock was issued per performance share unit.

See Note 13 for additional capital while accelerating the delineation of its position in the NW STACK, realizing further efficiencies and holding additional acreage by production, potentially adding reserves. The Company operates alldiscussion 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 share-based compensation awards.

~~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~~

3~~. Acquisitions and Divestitures~~

~~Acquisition of Properties.~~ On February 10, 2017, the Company acquired assets consisting of approximately 13,000 net acres in Woodward County, Oklahoma for approximately $47.7 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.~~ In 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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4.4. 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,~~March 31, 2019, and December 31, ~~2016.~~2018. Additionally, the carrying amount of debt associated with borrowings outstanding under the credit facility approximates fair value as borrowings bear interest at variable rates. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment classified as assets held for sale and related impairments, which are calculated using Level 3 inputs, are discussed in Note 4.5.



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~~from 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~~had no financial assets ~~and~~or liabilities where fair value differed from carrying value classified in ~~Level 1 and~~the fair

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value hierarchy as of March 31, 2019. The Company had assets classified in Level 2 of the hierarchy as of ~~September 30, 2017, and~~ December 31, ~~2016~~,2018, 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 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 unaudited condensed consolidated balance sheets.

Level 2 Fair Value Measurements

Commodity Derivative Contracts. The fair values of the Company’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. Fair value is determined through the use of a discounted cash flow model or option pricing model using the applicable inputs discussed above. The Company applies a weighted average credit default risk rating factor for its counterparties or gives effect to its credit default risk rating, as applicable, in determining the fair value of these derivative contracts. Credit default risk ratings are based on current published credit default swap rates.

~~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~~table summarizes the Company’s assets ~~and liabilities~~ measured at fair value on a recurring basis by the fair value hierarchy as of December 31, 2018(in thousands):

~~September 30, 2017~~

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~~2018


												Fair Value Measurements										Netting(1)	Assets/Liabilities at Fair Value
												Level 1		Level 2		Level 3
Assets											Assets
Commodity derivative contracts											Commodity derivative contracts	$	—	$	5,286	$	—	$	—	$	5,286

												$	—	$	5,286	$	—	$	—	$	5,286
	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Investments	$	7,541	$	—	$	—	$	—	$	7,541
	$	7,541	$	—	$	—	$	—	$	7,541
Liabilities
Commodity derivative contracts	$	—	$	29,714	$	—	$	—	$	29,714
	$	—	$	29,714	$	—	$	—	$	29,714

____________________

~~(1)~~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~~three-month periods ended ~~September 30, 2017,~~March 31, 2019 and ~~2016.~~2018.

5. Property, Plant and Equipment

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

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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 is secured by first priority mortgages on the Company’s real estate in Oklahoma City, Oklahoma (the “Building Note”) using a discounted cash flow analysis, which is classified as a Level 2 input in the fair value hierarchy. The estimated fair values and carrying values of the Company’s long-term debt are as follows (in thousands):

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 6 for additional discussion of the Company’s long-term debt.~~

~~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.

InDuring the first quarter of ~~2017,~~2018, the Company classified its remaining ~~drilling and oilfield services~~midstream generator assets as held for ~~sale in~~sale. These assets had a carrying value of $5.7 million which exceeded the ~~other current assets line of the unaudited condensed consolidated balance sheet. The~~estimated net realizable value of ~~the assets was determined to be $4.4~~$1.6 million based on expected sales prices obtained from third parties. As a ~~third party. The carrying value of these assets exceeded~~result, 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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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. The Company recorded an impairment of ~~$55.6~~$4.1 million ~~on its electrical transmission system~~for the three-month period ended March 31, 2018. The midstream generator assets were sold during the three and nine-month periods ended September 30, 2016, and a $1.7 million impairment on compressors and various other midstream services equipment during the nine-month period ended September 30, 2016, due primarily to the determination that their future use was limited.

~~Fair value measurements for the electrical asset impairment discussed above were based on replacement cost. As the fair value was estimated using the cost approach, inputs were based~~second quarter of 2018 with no gain or loss recognized on the ~~cost to a market participant buyer to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. These inputs~~sale. No significant assets were ~~not observable in the market and were classified as Level 3 in the fair value hierarchy.~~

~~The Company disposed of certain drilling and oilfield services assets previously~~ classified as held for sale ~~during 2016~~at March 31, 2019 or December 31, 2018.

~~and recorded losses on the sale of those assets of $0.1 million and $1.7 million for the three and nine-month periods ended~~

~~September 30, 2016, which are included in other operating (income) expense in the accompanying unaudited condensed consolidated statements of operations.~~

~~Drilling Carry Commitments.~~

6. Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of 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 fourth quarter of 2016 for approximately $1.2 million.following (in thousands):


	March 31, 2019		December 31, 2018
Accounts payable and other accrued expenses	$	89,909	$	78,219
Payroll and benefits	10,712		12,891
Production payable	12,972		12,767
Taxes payable	4,569		5,350
Drilling advances	724		2,031
Accrued interest	550		539
Total accounts payable and accrued expenses	$	119,436	$	111,797

6
~~. Long-Term Debt~~

Credit Facility. ~~On February 10, 2017, the $425.0~~The Company has a $600.0 million reserve-based revolving credit facility, ~~(the “First Lien Exit Facility”) was refinanced and replaced by~~which is subject to a ~~new $600.0~~$350.0 million ~~credit facility (the “Credit Facility”). The~~ borrowing ~~base under the Credit Facility is $425.0 million.~~base. This borrowing base ~~was reconfirmed during~~is currently under evaluation by the ~~October 2017 semi-annual~~Company and its lenders under the credit facility in connection with the scheduled spring redetermination. The next borrowing base redetermination after this is scheduled for ~~April~~October 1, ~~2018.~~2019. The ~~Credit Facility~~credit facility matures on March 31, 2020. ~~The outstanding~~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~~As of the end of each fiscal quarter, ~~ended June 30, 2017,~~ the ~~Credit Facility~~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.~~March 31, 2019, as its consolidated total net leverage ratio was 0.06 and its consolidated interest coverage ratio was 80.20.

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.~~March 31, 2019.

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respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving a liability of $25.0 million or more that are not paid; and ERISA events. Many events of default are subject to customary notice and cure periods.

The Company had ~~no amounts~~$20.0 million outstanding under the ~~Credit Facility~~credit facility at ~~September 30, 2017,~~March 31, 2019, and ~~$7.1~~$5.2 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 the Emergence Date,~~In February 2018, the Company ~~entered into~~fully repaid a note secured by a mortgage on the ~~Building Note,~~Company's downtown Oklahoma City real estate (the "Building Note") in the amount of $36.3 million, which ~~had~~was comprised of an initial principal amount of $35.0 ~~million. The Building Note was recorded at a fair value of $36.6~~ million ~~upon implementation of fresh start accounting. The resulting premium is being amortized to~~and $1.3 million in in-kind interest expense over the term of the Building Note. Interest is payable on the Building Note at 6% per annum for the first year following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. Interest costs that were ~~paid in kind and~~previously added to the ~~Building Note principal from~~principal. An unamortized premium of $1.2 million was recognized as a gain on extinguishment of debt in the ~~Emergence Date through May 11, 2017, which was 90 days after~~unaudited condensed consolidated statement of operations for the ~~refinancing of the First Lien Exit Facility. Interest became payable thereafter~~three-month period ended March 31, 2018 in ~~cash. The Building Note matures on October 2, 2021 and became prepayable in whole or in part~~

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~~(Unaudited)~~

without premium or penalty upon the refinancing of the First Lien Exit Facility. Net proceeds of $26.8 million received from the sale of the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordanceconnection with the ~~Plan.~~repayment.

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~~At March 31, 2019, the Company had no commodity derivative contracts in place. Historically, none of the Company’s commodity derivative contracts ~~may~~could 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, and the commodity derivative contract valuations are adjusted to the mark-to-market ~~valuation. At September 30, 2017, the Company’s commodity derivative contracts consisted~~valuation on a quarterly basis. The Board and management of ~~fixed price swaps under which~~ the Company ~~receives a fixed~~are continuing to evaluate the futures market for oil and natural gas to mitigate exposure to adverse oil and natural gas price ~~for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.~~changes.

The ~~Company recorded loss (gain) on commodity~~following table summarizes derivative ~~contracts of $11.7 million and $(0.3) million~~activity for the three-month periods ended ~~September 30, 2017,~~March 31, 2019, 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, and 2016, respectively, which include net cash receipts upon settlement of $7.7 million and $72.6 million, respectively. Included in the net cash receipts for the nine-month period ended September 30, 2016, is $17.9 million of cash receipts related to certain commodity derivative contracts settled prior to their contractual maturities (“early settlements”).2018 (in thousands):


	Three Months Ended March 31,
	2019		2018
Loss on commodity derivative contracts	$	209	$	18,330
Cash (received) paid on settlements	$	(5,078)	$	6,119

Master Netting Agreements and the Right of Offset. ~~The~~Historically, the Company has had 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 iswas limited to the net amounts due from its counterparties. As of September 30, 2017, the counterparties to the Company’s open commodity derivative contracts consisted of seven financial institutions, all of which are also lenders under the Company’s Credit Facility. The Company is not required to post additional collateral under its commodity derivative contracts as all of the counterparties to the Company’s commodity derivative contracts ~~share~~shared in the collateral supporting the Company’s ~~Credit Facility.~~credit facility.

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

~~September 30, 2017~~

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 ) $ —

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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 ) $ —

~~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, and~~ December 31, ~~2016~~,2018, on a gross basis without regard to same-counterparty netting (in thousands):

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 4 for additional discussion of the fair value measurement of the Company’s derivative contracts.

9. Commitments and Contingencies

Legal Proceedings. ~~On October 14,~~As previously disclosed, on May 16, 2016, ~~Lisa West~~the Company and ~~Stormy Hopson~~certain of its direct and indirect subsidiaries (collectively, the "Debtors") filed ~~an amended class action complaint~~voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States ~~District~~Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the joint plan of organization (the "Plan") of the Debtors 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

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~~complaint making allegations substantially similar to those contained~~directors who remain defendants in the ~~amended complaint~~Cases, the Company remains as a nominal defendant in each of the Cases so that ~~was previously dismissed.~~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. The Company indemnifies the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters. 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~~liabilities 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.

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Restricted Cash. Restricted cash - other included on the unaudited condensed consolidated balance sheets at ~~September 30, 2017,~~March 31, 2019, and December 31, ~~2016~~2018 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.

Common Stock, Performance Share Units, and ~~Uncertainties.~~Stock Options. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which depend on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company enters into commodity derivative arrangements in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 7 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 to fund its capital expenditures. Based on its cash balances, cash flows from operating activities and net borrowing availability under the Credit Facility,At March 31, 2019, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the next year; however, if oil or natural gas prices decline from current levels, they 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.

~~Common Stock.~~ ~~On 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 and approximately~~unvested restricted stock awards, 0.3 million unvested stock options, 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 1.0unvested performance share units, and 250.0 million shares of ~~Common Stock. The remaining balance of Convertible Notes converted to 14.1 million shares of Common Stock upon refinancing the First Lien Exit Facility.~~common stock authorized. See Note 613 for further discussion of the ~~Convertible Notes.~~Company’s restricted stock awards, performance share units, and stock options.

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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~~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.~~ 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,
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.~~

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,March 31, 2019. Thus, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, 2016. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the October 4, 2016 ownership change on its tax attributes. Previously, the Company planned to elect an available alternative upon filing its 2016 U.S. Federal income tax return that would not subject existing tax attributes to an immediate IRC Section 382 limitation but would have resulted in a full limitation should a subsequent ownership change occur within two years of the emergent date ownership change. Alternatively, upon filing its 2016 U.S. Federal income tax return, the Company elected a method that did subject tax attributes including net operating losses (“NOLs”) existing at October 4, 2016, to an annual limitation but provided more certainty with respect to the future availability of the Company’s existing NOLs. This limitation is expected to result in a significant portion of our NOL carryforwards expiring unused. As such, the Company’s deferred tax asset associated with NOLs and corresponding valuation allowance are expected to be materially less at December 31, 2017, compared to December 31, 2016. The election and resulting limitation did not result in anhad no federal 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 tax liability~~or benefit for the three-month periods ended March 31, 2019 and 2018, and an insignificant amount of state income tax ~~year ended December 31, 2016 and is not expected to result in a tax liability~~expense for the ~~tax year ending December~~three-month period ended March 31, ~~2017.~~2018.

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~~net operating loss and other carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years.

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12. 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 ~~(loss) earnings~~loss per share:


									Net Loss		Weighted Average Shares	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)

Three Months Ended March 31, 2019								Three Months Ended March 31, 2019
Basic loss per share	$	(8,485	)	34,290	$	(0.25	)	Basic loss per share	$	(5,277)	35,322	$	(0.15)
Effect of dilutive securities								Effect of dilutive securities
Restricted stock awards(1)	—			—				Restricted stock awards(1)	—		—
Performance share units(1)	—			—				Performance share units(1)	—		—
Warrants(1)								Warrants(1)	—		—
Stock options(1)								Stock options(1)	—		—
Diluted loss per share	$	(8,485	)	34,290	$	(0.25	)	Diluted loss per share	$	(5,277)	35,322	$	(0.15)


Three Months Ended September 30, 2016 (Predecessor)
Three Months Ended March 31, 2018								Three Months Ended March 31, 2018
Basic loss per share	$	(404,337	)	718,373	$	(0.56	)	Basic loss per share	$	(40,894)	34,575	$	(1.18)
Effect of dilutive securities								Effect of dilutive securities
Restricted stock and units(2)	—			—
Restricted stock awards(2)								Restricted stock awards(2)	—		—
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	$	(40,894)	34,575	$	(1.18)


Nine Months Ended September 30, 2017 (Successor)
Basic earnings per share	$	65,822		31,750	$	2.07
Effect of dilutive securities
Restricted stock awards	—			234
Performance share units(3)	—			—
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.No incremental shares of potentially dilutive restricted stock awards, performance share units, warrants or stock options were included for the three-month period ended March 31, 2019, as their effect was antidilutive under the treasury stock method.

2.No incremental shares of potentially dilutive restricted stock awards or warrants were included for the three-month period ended March 31, 2018, as their effect was antidilutive under the treasury stock method.

3.Performance share units covering an insignificant amount of shares for the three-month period ended March 31, 2018, were excluded from the computation of loss per share because their effect would have been antidilutive.

See Note 13 for discussion of the Company’s share-based compensation awards.

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~~12.~~13. 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,~~March 31, 2019, the Company had restricted stock awards and an immaterial amount of performance share units and ~~performance units~~stock options outstanding under the Omnibus Incentive Plan. At March 31, 2018, the Company also had performance units outstanding which vested in June 2018 with an aggregate intrinsic value of approximately $1.7 million.

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 for approximately 1.4 million shares of restricted stock were granted under the Omnibus Incentive Plan. These~~Outstanding restricted shares will generally vest over either a one-year period or three-year period. ~~In 2017, awards for~~As of March 31, 2019, the Company had approximately ~~0.6~~0.4 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.~~

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

Asshares outstanding at weighted average grant date fair value of ~~September 30, 2017, the Successor Company’s~~$16.07, and unrecognized compensation cost related to ~~unvested restricted stock~~these awards ~~was $25.0~~totaled $3.9 million. The remaining ~~weighted-average~~weighted average contractual period over which this compensation cost may be recognized is ~~2.0~~2.1 years.

The ~~Successor Company’s~~following tables summarize share and incentive-based compensation for the three-month periods ended March 31, 2019, and 2018 (in thousands):


	Recurring Compensation Expense(1)		Executive Terminations(2)		Reduction in Force(2)		Total
Three Months Ended March 31, 2019
Equity-classified awards:
Restricted stock awards	$	745	$	—	$	—	$	745
Performance share units	198		—		—		198
Stock options	130		—		—		130
Total share-based compensation expense	1,073		—		—		1,073



Less: Capitalized compensation expense	(77)		—		—		(77)
Share-based compensation expense, net	$	996	$	—	$	—	$	996

Three Months Ended March 31, 2018
Equity-classified awards:
Restricted stock awards	$	2,776	$	8,140	$	3,686	$	14,602
Performance share units	329		974		150		1,453
Total share-based compensation expense	3,105		9,114		3,836		16,055
Liability-classified awards:
Performance units	530		2,367		589		3,486
Total share and incentive-based compensation expense	3,635		11,481		4,425		19,541
Less: Capitalized compensation expense	(210)		—		—		(210)
Share and incentive-based compensation expense, net	$	3,425	$	11,481	$	4,425	$	19,331

____________________

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. Vesting for certain stock restricted stock awards, ~~are equity-classified awards.~~

~~Performance Share Units.~~ ~~In February 2017, the Company granted~~ performance share units, which vest upon completion of the performance period, which is January 1, 2017 through June 30, 2019. The performance share units will be 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 one share of the Company Common Stock per performance share unit as awarded 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 units 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.

~~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.~~accelerated in connection with executive terminations and a reduction in force in the first quarter of 2018.

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~~Predecessor Share-Based Compensation~~

14. Revenues

The following table disaggregates the Company’s revenue by source for the three-month periods ended March 31, 2019 and 2018:


	Three Months Ended March 31,
	2019		2018


Oil	$	43,159	$	53,335
NGL	13,111		16,389
Natural gas	16,778		17,242
Other	188		162
Total revenues	$	73,236	$	87,128

Oil, natural gas and NGL revenues. ~~Restricted Common Stock Awards.~~ Prior to the cancellation of the Predecessor Company’s share-based compensation awards on the Emergence Date, the then-existing restricted common stock awards generally vested over a four-year period, subject to certain conditions, and were valued based upon the market valueA majority of the Company’s ~~common stock~~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 ~~date~~terms of ~~grant. For~~ the ~~three~~contract. Oil, natural gas and ~~nine-month periods ended September 30, 2016,~~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 ~~recognized total share-based compensation expense~~delivers the related production to its ~~restricted stock awards~~customers. As of ~~$1.8~~March 31, 2019, and December 31, 2018, the Company had revenues receivable of $28.1 million and ~~$11.2~~$31.8 million, ~~of which $0.5 million~~respectively, and ~~$1.7 million were capitalized, respectively. Share-based compensation~~did not record any bad debt expense ~~for~~on revenues receivable during the ~~nine-month~~three-month period ended September 30, 2016, included $5.4 million for the accelerated vesting of 1.3 million restricted common stock awards related to the Predecessor Company’s reduction in workforce during the first quarter of 2016. There was no significant activity related to the Predecessor Company’s then-outstanding restricted stock units, performance unitsMarch 31, 2019.

Practical expedients and ~~performance share units during the three and nine-month periods ended September 30, 2016. The following table presents a summary~~exemptions. Most of the ~~Predecessor Company’s unvested restricted stock awards.~~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.

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

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.

Table of Contents

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~~2018 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~~three-month periods ended ~~September 30, 2017~~,March 31, 2019, and ~~2016~~,2018, 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~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016~~2018 include the following:

Total production for the three-month period ended September 30, 2017, was comprised of approximately 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. Total production for the nine-month period ended September 30, 2017, was comprised of approximately 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.


	Three Months Ended March 31,
	2019					2018
	Gross Wells Drilled(2)	Net Wells Drilled(2)	Average Rigs Drilling	Gross Wells Drilled(2)	Net Wells Drilled(2)	Average Rigs Drilling
Area
Mid-Continent (1)	8	2.9	1.7	6	1.4	1.6
North Park Basin	4	4.0	1.0	5	5.0	1.2
Total	12	6.9	2.7	11	6.4	2.8

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

~~Drilled nine and 14~~1.Five wells ~~respectively, in the Mid-Continent during the three and nine-month periods ended September 30, 2017, compared to three and 13 wells~~ were 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~~under our 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~~in the NW ~~STACK. See “Note 2 - Recent Transactions” to~~STACK during each of the ~~accompanying unaudited condensed consolidated financial statements for additional discussion~~three-month periods ended March 31, 2019 and 2018. 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.~~

~~Discontinued all remaining~~agreement has been billed costs totaling $81.4 million for 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 substantially all oil and natural gas properties and midstream assets located in~~completion activity from inception through March 31, 2019, under the ~~Piñon field in~~initial $100.0 million tranche of the ~~WTO and $11.0 million in cash~~agreement. This agreement is expected 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 millionbe fulfilled in the second quarter of ~~2017 from~~2019. A second $100.0 million tranche is subject to mutual agreement.

2.Includes wells with a rig release date during the ~~original range~~three-month period ended March 31, 2019 or 2018, respectively.

Table of ~~$210.0~~Contents

The chart below shows production by product for the three-month periods ended March 31, 2019 and 2018:

Outlook

Our focus in 2019 is to develop our inventory of NW STACK and North Park Basin drilling opportunities and pursue value enhancing opportunities in the Mid-Continent. We will also pursue accretive acquisitions of strategic assets that provide high quality production and development upside. Focusing on cost reductions, margin improvements and opportunistic divestment of core and non-core properties will also be a part of our plan moving forward. Based on these strategic objectives, we intend to spend between $160.0 million ~~to $220.0 million.~~and $180.0 million as part of our 2019 capital budget plan. The ~~increase in capital~~substantial majority of these budgeted expenditures is ~~allowing~~designated for ~~continued development~~drilling and completion activities. Based on our 2019 capital spending plans, we estimate that our production will experience a 5%-6% decline compared to full year 2018 production. We will continue to monitor the changing market conditions and the results of ~~these assets~~our operations and will take measures to help achieve our strategic objectives, enhance shareholder value and improve our competitiveness in the ~~fourth quarter of 2017 by funding (i) the establishment of two federal units and additional infrastructure in~~marketplace. We will endeavor to keep our ~~North Park acreage, and (ii) the acquisition of 3D seismic and core analysis~~capital spending within or very close to ~~support~~ our ~~NW STACK drilling program.~~projected cash flows from operations subject to changing industry conditions or events.

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. The historical twelve-month unweighted average prices at September 30, 2017 were $49.81 per barrel of oil and $3.00 per Mcf of natural gas. Applying the actual October 1, 2017 and November 1, 2017 benchmark commodities prices, the twelve-month unweighted average prices would be $50.73 per barrel of oil and $3.01 per Mcf of natural gas through November 2017.

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.~~contracts, if any. 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~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016~~2018 are shown in the table below:


	Three Months Ended March 31,
	2019		2018
Oil (per Bbl)	$	54.90	$	62.89
Natural gas (per MMBtu)	$	2.87	$	2.85

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.

Table of Contents

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~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016.~~2018:


										Three Months Ended March 31,
	Three Months Ended September 30,				Nine Months Ended September 30,
	Successor		Predecessor		Successor		Predecessor			2019		2018
	2017		2016		2017		2016
Production data (in thousands)

Production data									Production data
Oil (MBbls)	954		1,282		3,130		4,315		Oil (MBbls)	849		926
NGL (MBbls)	807		1,103		2,601		3,358		NGL (MBbls)	875		700
Natural gas (MMcf)	10,850		13,079		33,883		44,124		Natural gas (MMcf)	8,620		9,487
Total volumes (MBoe)	3,569		4,565		11,378		15,027		Total volumes (MBoe)	3,161		3,207
Average daily total volumes (MBoe/d)	38.8		49.6		41.7		54.8		Average daily total volumes (MBoe/d)	35.1		35.6
Average prices—as reported(1)									Average prices—as reported(1)
Oil (per Bbl)	$	46.16	$	42.82	$	47.22	$	36.85	Oil (per Bbl)	$	50.84	$	57.60
NGL (per Bbl)	$	19.07	$	13.90	$	16.52	$	12.67	NGL (per Bbl)	$	14.98	$	23.41
Natural gas (per Mcf)	$	1.95	$	2.27	$	2.14	$	1.78	Natural gas (per Mcf)	$	1.95	$	1.82
Total (per Boe)	$	22.57	$	21.89	$	23.14	$	18.63	Total (per Boe)	$	23.11	$	27.12
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)	$	50.84	$	49.20
NGL (per Bbl)	$	19.07	$	13.90	$	16.52	$	12.67	NGL (per Bbl)	$	14.98	$	23.41
Natural gas (per Mcf)	$	2.10	$	2.32	$	2.16	$	1.77	Natural gas (per Mcf)	$	2.54	$	1.99
Total (per Boe)	$	23.97	$	25.10	$	23.81	$	22.70	Total (per Boe)	$	24.72	$	25.21

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~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016.~~2018:

1.The Permian Basin properties were sold in the fourth quarter of 2018.

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 %

Table of Contents

Revenues

Consolidated revenues for the ~~Successor Period~~three-month periods ended March 31, 2019, and ~~Predecessor Period~~2018 are presented in the table below (in thousands):


	Three Months Ended March 31,

	2019		2018
Oil	$	43,159	$	53,335
NGL	13,111		16,389
Natural gas	16,778		17,242
Other	188		162
Total revenues	$	73,236	$	87,128

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

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~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016~~2018 are shown in the ~~tables~~table below (in thousands):

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



2018 oil, natural gas and NGL revenues	$	86,966
Change due to production volumes	(1,913)
Change due to average prices	(12,005)
2019 oil, natural gas and NGL revenues	$	73,048

Revenues from oil, natural gas and NGL sales decreased ~~$19.4~~$13.9 million, or ~~19.4%~~16.0% for the three-month period ended ~~September 30, 2017,~~March 31, 2019, compared to the same period in ~~2016, largely~~2018, respectively, due primarily 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 from oil,~~production during the 2019 period. Oil and natural gas ~~and NGL sales decreased by $16.7 million, or 6.0%, for~~production also declined in the ~~nine-month period ended September 30, 2017,~~first quarter of 2019 compared to the ~~same period in 2016, primarily~~first quarter of 2018 largely due to ~~the~~natural declines in ~~production as noted above,~~existing producing wells in the Mid-Continent and the sale of our Permian properties in the fourth quarter of 2018, which were ~~largely~~partially offset by ~~an increase~~added production from the purchase of additional interests 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.

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 allcertain oil and natural gas properties ~~and midstream assets located~~ in the ~~Piñon field~~Mississippian Lime and NW STACK areas of Oklahoma and Kansas in the ~~WTO to Occidental in January 2016.~~fourth quarter of 2018.

Expenses

Expenses for the ~~three and nine-month~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016~~2018 consisted of the following (in thousands):


	Three Months Ended March 31,

	2019		2018

Lease operating expenses	$	22,779	$	23,519
Production, ad valorem, and other taxes	5,080		6,234
Depreciation and depletion—oil and natural gas	36,465		27,997
Depreciation and amortization—other	2,943		3,153
Impairment	—		4,170
General and administrative	9,939		13,682

Proxy contest	—		407
Employee termination benefits	—		31,587
Loss on derivative contracts	209		18,330

Other operating expense	82		16
Total expenses	$	77,497	$	129,095

Table of Contents

Three Months Ended September 30, Nine Months Ended September 30,
Successor Predecessor Successor Predecessor
2017 2016 2017 2016
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
Financial Metrics


	Three Months Ended March 31,

	2019			2018

Lease operating expenses ($/Boe)	$	7.21		$	7.33
Production, ad valorem, and other taxes ($/Boe)	$	1.61		$	1.94
Depreciation and depletion—oil and natural gas ($/Boe)	$	11.54		$	8.73
Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue)	7.0		%	7.2		%

~~Production expense includes costs associated with our exploration~~

Lease operating expenses and production, ~~activities, including, but not limited to, lease operating expense~~ad valorem, and ~~treating costs. Production costs per Boe decreased to $7.50 and $6.77~~other taxes remained relatively consistent for the ~~three and nine-month periods~~three-month period ended September 30, 2017, from $8.68 per Boe and $8.63 per Boe for the same 2016 periods, respectively, primarily due to (i) the Successor Company’s presentation 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,March 31, 2019, compared to the ~~Predecessor Company’s presentation of transportation costs totaling $8.0 million and $26.2 million as production expenses for the~~ same ~~2016 periods, respectively, and (ii) controlled reductions in expenditures for electricity, chemicals and various other costs.~~2018 period.

Depreciation and depletion for our oil and natural gas properties increased by ~~$3.3~~$8.5 million or $2.81/Boe for the three-month period ended ~~September 30, 2017,~~March 31, 2019, compared to the same period in ~~2016, primarily due to an~~2018. This rate increase ~~in the~~is a result of development activities where our finding and development costs are higher than historical depreciation and depletion rates. As a result, average depletion ~~rate~~rates have increased and may continue to ~~$8.69 per Boe compared to $6.07 per Boe~~increase as we develop these areas.

Impairment for the 2016 period. The increase in the average depletion rate primarily resulted from (i) incurring higher actual drilling and completion costs per Boe during the 2017 period compared to the rate per Boe calculated at December 31, 2016 following the significant ceiling test write-down incurred in the fourth quarter of 2016, and (ii) a shift of more capital to develop our North Park Basin oil asset 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.

~~Depreciation and depletion for our oil and natural gas properties decreased by $3.5 million for the nine-month~~three-month period ended ~~September 30, 2017, compared~~March 31, 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 for the nine-month period ended September 30, 2017, compared to $6.05 per Boe for 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.estimated net realizable value.

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 of the following (in thousands):~~

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~~$3.7 million, or ~~30.4%~~27.4% for the three-month period ended ~~September 30, 2017,~~March 31, 2019, from the same period in ~~2016~~2018 due primarily to (i) a ~~$13.0~~$2.5 million decrease in ~~net salary~~compensation-related costs largely resulting from a reduction in force during the ~~fourth~~first quarter of ~~2016~~2018 as well as additional declines in headcount throughout 2018, and ~~recording an adjustment to the 2016 retention incentive accrual in the third quarter~~(ii) a decrease of ~~2016. This decrease was partially offset by (i) an increase of $2.7~~$1.2 million in professional services costs ~~due to transaction fees~~ and ~~(ii) an increase of $1.4 million in~~ other miscellaneous ~~costs.~~

~~General~~general and administrative ~~expenses decreased $70.4 million, or 52.4%~~items.

Employee termination benefits for the ~~nine-month~~three-month period ended September 30, 2017, from 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 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,~~2018, include cash and ~~(iv) a decrease of $13.5 million in~~share-based severance costs incurred ~~due~~ primarily toas a result of (i) the reduction in force ~~that occurred during~~in the first quarter of ~~2016. These decreases were partially offset by an increase~~2018 and (ii) severance costs associated with the departure of ~~$2.3 million~~executive officers and other senior officers. See "Note 3 - Employee Termination Benefits" in ~~other miscellaneous costs.~~the accompanying unaudited condensed consolidated financial statements for additional discussion of these expenses.

~~We recorded loss (gain) on commodity~~The following table summarizes derivative ~~contracts of $11.7 million and $(0.3) million~~activity for the three-month periods ended ~~September 30,~~March 31, 2019, and 2018 (in thousands):


	Three Months Ended March 31,
	2019		2018
Loss on commodity derivative contracts	$	209	$	18,330
Cash (received) paid on settlements	$	(5,078)	$	6,119

On November 14, 2017, we entered into an Agreement and ~~2016, respectively,~~Plan of Merger (the "merger") with Bonanza Creek Energy, Inc. ("Bonanza Creek") which was subsequently terminated in December 2017. 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 November 2017. We recorded losses on these oil derivatives of $5.8 million for the three-month period ended March 31, 2018, which include net cash ~~receipts~~payments 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, and 2016, respectively, which include net cash receipts upon settlement of $7.7 million and $72.6 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.$1.2 million.

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

We had no commodity derivative contracts outstanding at March 31, 2019.

~~Loss on settlement~~

Table of ~~contracts for the nine-month period ended September 30, 2016, includes a $78.9 million loss resulting from the termination of a gas treating and CO~~₂ ~~delivery agreement with Occidental as well as a loss of $11.2 million recorded for the cease-use of transportation agreements that supported production from the Piñon field.~~Contents

~~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~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016~~2018 are presented in the table below (in thousands).


	Three Months Ended March 31,
	2019		2018
Other (expense) income
Interest expense, net	$	(585)	$	(948)
Gain on extinguishment of debt	—		1,151

Other (expense) income, net	(431)		873
Total other (expense) income	$	(1,016)	$	1,076

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

~~fees incurred~~March 31, 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,~~March 31, 2019, our cash and cash equivalents, excluding restricted cash, were ~~$133.2~~$7.4 million. Additionally, we had ~~approximately $37.6~~$20.0 million ~~in total~~of current debt outstanding under our $350.0 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$5.2 million in outstanding letters of credit, which reduce the amount available under the ~~Credit Facility.~~credit facility. As of May 2, 2019, the Company had approximately $10.7 million in cash and cash equivalents, excluding restricted cash, $40.0 million outstanding under our credit facility, and $5.2 million in outstanding letters of credit. The credit facility borrowing base is currently under evaluation by the Company and its lenders under the credit facility in connection with the scheduled spring redetermination.

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, which terminates on March 31, 2020, as discussed in “—Credit Facility” below.

Our working capital ~~surplus decreased~~deficit increased to ~~$24.2~~$101.1 million at ~~September 30, 2017,~~March 31, 2019, compared to ~~$43.5~~$63.9 million at December 31, ~~2016,~~2018, largely due to borrowings on the ~~acquisition~~credit facility becoming due in the next 12 months, fluctuations in the timing and amount of ~~oil~~payments of accounts payable and ~~natural gas properties for approximately $47.7 million in cash~~accrued expenses, and the settlement of all remaining derivative contracts in the first quarter of ~~2017.~~2019. This ~~decrease~~increase is partially offset by fluctuations in the timing and amount of collections of ~~receivables~~receivables.

We intend to spend between $160.0 million and ~~payments~~$180.0 million in our 2019 capital budget plan, with the majority of ~~accounts payable~~those expenditures being allocated to drilling and ~~accrued expenses as well as changes in derivative assets and liabilities due~~completion activities. We intend to ~~quarterly mark-to-market adjustments.~~

~~As noted in~~ ~~“— Outlook,”~~ ~~in the second quarter of 2017, we increased our 2017~~fund capital expenditures ~~budget to a range between $250.0 million~~ and ~~$260.0 million. The increase in budgeted capital expenditures is offset by asset sales, continued declining production costs, and increased 2017 production expectations, lessening~~other commitments for the ~~impact to future liquidity. Management intends to fund remaining 2017 capital expenditures~~next 12 months using cash flow from our operations, borrowings under our credit facility and cash on ~~hand and, if necessary, borrowings under the Credit Facility discussed below.~~hand. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.

Cash Flows

Our cash flows from operations, ~~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~~2018 through ~~September 2017,~~March 2019, the ~~month-end~~ NYMEX settled price for oil fluctuated between a high of ~~$60.30~~$76.41 per Bbl in ~~May 2015~~October 2018 and a low of ~~$33.62~~$42.53 per Bbl in ~~January 2016,~~December 2018, and the month-end NYMEX settled price for gas fluctuated between a high of ~~$3.93~~$4.72 per MMBtu in ~~January 2017~~December 2018 and a low of ~~$1.71~~$2.64 per MMBtu in March ~~2016.~~

2018.

Table of Contents

Our cash flows for the ~~nine-month~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016~~2018 are presented in the following table and discussed below (in thousands):


	Three Months Ended March 31,
	2019		2018
Cash flows provided by operating activities	$	31,570	$	30,407
Cash flows used in investing activities	(61,587)		(64,572)
Cash flows provided by financing activities	19,707		(37,965)
Net decrease in cash and cash equivalents	$	(10,310)	$	(72,130)

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 million increase in operating~~Operating cash flows remained relatively consistent for the ~~nine-month~~three-month period ended ~~September 30, 2017,~~March 31, 2019, compared to the same period in 2016, is primarily due to (i) a reduction in cash paid for interest expense, (ii) a reduction in 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.2018. 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 period~~three-month periods 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 million in cash~~March 31, 2019 and capital expenditures for exploration and production, which were partially offset by proceeds from the sale of various non-core oil and natural gas properties and certain drilling equipment previously classified as held for sale. During the nine-month period ended September 30, 2016,2018, cash flows used in investing activities primarily consisted of capital expenditures for ~~exploration~~drilling and ~~production activities, which were slightly offset by proceeds from the sale of various non-core oil and natural gas properties.~~ completion activities.

Capital expenditures ~~on an accrual basis~~ for the ~~nine-month~~three-month periods ended ~~September 30, 2017,~~March 31, 2019, and ~~2016~~2018 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


	Three Months Ended March 31,
	2019		2018
Capital Expenditures (on an accrual basis)
Drilling and completion	$	70,232	$	35,345
Leasehold and geophysical	1,069		1,977
Other - operating	—		(53)
Other - corporate	143		—
Capital expenditures, excluding acquisitions	71,444		37,269
Acquisitions	(326)		—
Total	$	71,118	$	37,269

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 provided by financing activities ~~used $5.3~~was approximately $19.7 million ~~of cash~~ for the ~~nine-month~~three-month period ended ~~September 30, 2017,~~March 31, 2019, which consisted primarily of net borrowings under the credit facility. Our cash used in financing activities was approximately $38.0 million during the three-month period ended March 31, 2018, which consisted of the ~~purchase~~repayment of the Building Note and cash paid for employee tax obligations in connection with the 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 of 2016.awards.

Indebtedness

~~Long-termdebt consists of the following 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~~We had $20.0 million ~~Credit Facility with a $425.0 million borrowing base. 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~~current debt outstanding under our credit facility at 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.~~

2019. The ~~initial~~ borrowing base under the ~~Credit Facility was $425.0~~credit facility is $350.0 million ~~which was reconfirmed~~and is currently under evaluation by the Company and its lenders under the credit facility in connection with the ~~October 2017 borrowing base~~scheduled spring redetermination. The next semi-annual borrowing base redetermination after this is scheduled for ~~April~~October 1, ~~2018.~~2019. The ~~Credit Facility~~credit facility matures on March 31, 2020. The credit facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all proved reserves included in ~~the~~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~~

Table of Contents

(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.~~March 31, 2019 as our consolidated total net leverage ratio was 0.06 and our consolidated interest coverage ratio was 80.20.

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 entered into the Building Note, which had an initial principal amount of $35.0 million and is secured by first priority mortgages on the Company’s real estate in Oklahoma City, Oklahoma. 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, and 10% thereafter through maturity. Interest on the Building Note was initially payable in kind. Approximately $1.3 million in in-kind interest costs were 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 without premium or penalty upon the refinancing of the First Lien Exit Facility.

See “Note 67 - ~~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,~~2018, 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.

The Company's current maturities of long-term debt increased by $20.0 million at March 31, 2019 compared to December 31, 2018, due to net borrowings on the Company's credit facility, which matures in March 2020. Other than the ~~conversion of~~borrowings on the Convertible Notes discussed in “—Overview,” and the drilling participation agreement discussed in “—Overview” and “Note 2 - Recent Transactions” to the accompanying unaudited condensed consolidated financial statements,credit facility, there were no other significant changes in contractual obligations and off-balance sheet arrangements from those reported in the ~~2016~~2018 Form 10-K.

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~~2018 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~~three months of ~~2017.~~2019.

~~Valuation Allowance~~

~~Upon emergence from bankruptcy and the application~~

Table 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.Contents

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,~~Historically, we have used a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At ~~September 30, 2017, our~~March 31, 2019, we had no 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.~~

place.

At
~~September 30, 2017, our open commodity~~

The following table summarizes 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

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.

~~We recorded loss (gain) on commodity derivative contracts of $11.7 million and $(0.3) million~~activity for the three-month periods ended ~~September 30, 2017,~~March 31, 2019, 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, and 2016, respectively, which include net cash receipts upon settlement of $7.7 million and $72.6 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.2018 (in thousands):


	Three Months Ended March 31,
	2019		2018
Loss on commodity derivative contracts	$	209	$	18,330
Cash (received) paid on settlements	$	(5,078)	$	6,119

See “Note 78 - Derivatives” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding our commodity derivatives.

Credit Risk. ~~All~~Historically, 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~~to our past derivative transactions have had an “investment grade” credit rating. WeWhen derivative contracts are outstanding, 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~~Historically, our derivative contracts ~~are~~have been with multiple counterparties to minimize exposure to any individual counterparty.

We dohave not ~~require~~required collateral or other security from counterparties to support derivative instruments. We have historically had 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,~~This limited our maximum amount of loss under derivative transactions due to credit ~~risk is limited~~ to the net amounts due from the counterparties under ~~the~~any outstanding commodity derivative contracts. Our ~~loss is~~past losses have been further limited as any amounts due from a defaulting counterparty that iswas also a lender under the ~~Credit Facility can be~~credit facility were offset against amounts owed, if any, to such counterparty. As of September 30, 2017, the counterparties to our open commodity derivative contracts consisted of seven financial institutions, all of which are also lenders under our 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~~obligation on this instrument is periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate. We had no$20 million in outstanding variable rate debt as of ~~September 30, 2017.~~March 31, 2019.

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~~CEO and ~~Chief Financial Officer,~~CFO, 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~~CEO and ~~Chief Financial Officer~~CFO concluded that the Company’s disclosure controls and procedures were effective as of ~~September 30, 2017,~~March 31, 2019, 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

Table of Contents

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,~~March 31, 2019 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

Table of Contents

PART II. Other Information

ITEM 1. Legal Proceedings

~~On October 14,~~As previously disclosed, on May 16, 2016, ~~Lisa West and Stormy Hopson~~the Debtors filed ~~an amended class action complaint in~~voluntary petitions for reorganization under Chapter 11 of the United States ~~District~~Bankruptcy Code in the Bankruptcy Court. The Bankruptcy Court ~~for~~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

Although the Cases have not been dismissed against ~~SandRidge Exploration~~certain former officers 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 containeddirectors who remain defendants in the ~~amended complaint~~Cases, the Company remains as a nominal defendant in each of the Cases so that ~~was previously dismissed.~~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. The Company indemnifies the SandRidge Mississippian Trust I and SandRidge Mississippian Trust II against losses, claims, damages, liabilities and expenses, including reasonable costs of investigation and attorney’s fees and expenses arising out of certain legal matters. 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~~liabilities relating to ~~this action.~~any of the Cases.

ITEM 1A. Risk Factors

There have been no material changes to the risk factors previously discussed in Item 1A—Risk Factors in the ~~Company’s 2016~~Company's 2018 Form 10-K.

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

None.

~~The following table presents a summary of share repurchases made by the Company during the three-month period ended~~ ~~September 30, 2017~~.

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.

Table of Contents

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

10.2.3†

Form of Option Award Agreement for Amen ded and Restated SandRidge Energ y, Inc. 2016 Omnibus Incentive Plan

10-K

001-33784

10.2.3

3/4/2019

10.3.6†

Offer Letter to Paul D. McKinney , dated as of January 28, 2019

8-K

001-33784

10.1

1/28/2019

10.3.7†

SandRidge Energy, Inc. Special Severance Plan 2018, effective as of April 1, 2018

10.3.8†

First Amendment to SandRidge Energy, Inc. Special Severance Plan 2018, effective as of December 17, 2018

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

† Management contract or compensatory plan or arrangement

Table of Contents

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~~

~~EXHIBIT INDEX~~

May 9, 2019

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             *


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)


	March 31, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents	$	7,354	$	17,660

Restricted cash - other	1,981		1,985
Accounts receivable, net	51,053		45,503
Derivative contracts	—		5,286
Prepaid expenses	3,128		2,628
Other current assets	251		265
Total current assets	63,767		73,327
Oil and natural gas properties, using full cost method of accounting
Proved	1,344,552		1,269,091
Unproved	57,363		60,152
Less: accumulated depreciation, depletion and impairment	(614,972)		(580,132)
	786,943		749,111
Other property, plant and equipment, net	200,014		200,838

Other assets	820		1,062
Total assets	$	1,051,544	$	1,024,338



LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	119,436	$	111,797
Current maturities of long-term debt	20,000		—

Asset retirement obligation	25,355		25,393
Other current liabilities	29		—
Total current liabilities	164,820		137,190


Asset retirement obligation	35,836		34,671

Other long-term obligations	7,428		4,756
Total liabilities	208,084		176,617
Commitments and contingencies (Note 9)
Stockholders’ Equity
Common stock, $0.001 par value; 250,000 shares authorized; 35,687 issued and outstanding at March 31, 2019 and December 31, 2018	36		36
Warrants	88,518		88,516
Additional paid-in capital	1,056,235		1,055,164
Accumulated deficit	(301,329)		(295,995)
Total stockholders’ equity	843,460		847,721
Total liabilities and stockholders’ equity	$	1,051,544	$	1,024,338



	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


	March 31, 2019		December 31, 2018
Oil and natural gas properties
Proved	$	1,344,552	$	1,269,091
Unproved	57,363		60,152
Total oil and natural gas properties	1,401,915		1,329,243
Less accumulated depreciation, depletion and impairment	(614,972)		(580,132)
Net oil and natural gas properties capitalized costs	786,943		749,111

Land	4,400		4,400
Electrical infrastructure	131,176		131,176
Other non-oil and natural gas equipment	13,410		13,458
Buildings and structures	77,148		77,148
Financing leases	1,727		—
Total	227,861		226,182
Less accumulated depreciation and amortization	(27,847)		(25,344)
Other property, plant and equipment, net	200,014		200,838
Total property, plant and equipment, net	$	986,957	$	949,949



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



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



	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



	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	)	$	—



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	)


~~(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.



	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



	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


~~(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.~~



	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