Edgar Filing: SANDRIDGE ENERGY INC

Notional (MBbls)

Weighted Average
Fixed Price

July 2017 - December 2017

January 2018 - December 2018

Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________

Form 10-Q

__________________________

(Mark One)



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

For the quarterly period ended June 30, 2017



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

For the transition period from to

Commission File Number: 001-33784

__________________________

SANDRIDGE ENERGY, INC.

(Exact name of registrant as specified in its charter)

__________________________



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

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

Registrant’s telephone number, including area code:

(405) 429-5500

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

__________________________

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

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

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



Large accelerated filer	o		Accelerated filer	o
Non-accelerated filer	þ	(Do not check if a smaller reporting company)	Smaller reporting company	o
			Emerging growth company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities 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

The number of shares outstanding of the registrant’s common stock, par value $0.001 per share, as of the close of business on July 31, 2017, was 35,827,718.

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

DISCLOSURES REGARDING FORWARD-LOOKING STATEMENTS

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

FORM 10-Q

Quarter Ended June 30, 2017

INDEX



PART I. FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statement of Changes in Stockholders’ Equity	7
	Condensed Consolidated Statements of Cash Flows	8
	Notes to Condensed Consolidated Financial Statements	9
ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	36
ITEM 4.	Controls and Procedures	38

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	39
ITEM 1A.	Risk Factors	39
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	39
ITEM 3.	Defaults upon Senior Securities	39
ITEM 6.	Exhibits	39

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PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited)

(In thousands, except per share data)



	June 30, 2017			December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	148,400		$	121,231
Restricted cash - collateral	—			50,000
Restricted cash - other	2,840			2,840
Accounts receivable, net	57,168			74,097
Derivative contracts	17,828			—
Prepaid expenses	3,925			5,375
Other current assets	9,914			3,633
Total current assets	240,075			257,176
Oil and natural gas properties, using full cost method of accounting
Proved	934,248			840,201
Unproved	111,202			74,937
Less: accumulated depreciation, depletion and impairment	(404,143		)	(353,030		)
	641,307			562,108
Other property, plant and equipment, net	242,291			255,824
Derivative contracts	7,478			—
Other assets	1,527			6,284
Total assets	$	1,132,678		$	1,081,392

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - Continued

(In thousands, except per share data)



	June 30, 2017			December 31, 2016
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable and accrued expenses	$	113,019		$	116,517
Derivative contracts	—			27,538
Asset retirement obligations	65,893			66,154
Other current liabilities	8,270			3,497
Total current liabilities	187,182			213,706
Long-term debt	37,679			305,308
Derivative contracts	—			2,176
Asset retirement obligations	41,953			40,327
Other long-term obligations	1,703			6,958
Total liabilities	268,517			568,475
Commitments and contingencies (Note 7)
Stockholders’ Equity
Common stock, $0.001 par value; 250,000 shares authorized; 35,797 issued and outstanding at June 30, 2017 and 21,042 issued and 19,635 outstanding at December 31, 2016	34			20
Warrants	88,381			88,381
Additional paid-in capital	1,035,421			758,498
Accumulated deficit	(259,675		)	(333,982		)
Total stockholders’ equity	864,161			512,917
Total liabilities and stockholders’ equity	$	1,132,678		$	1,081,392

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)

(In thousands, except per share data)



	Three Months Ended June 30,						Six Months Ended June 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Revenues
Oil, natural gas and NGL	$	84,546		$	95,662		$	182,695		$	180,037
Other	305			3,759			506			9,716
Total revenues	84,851			99,421			183,201			189,753
Expenses
Production	25,209			42,686			50,232			89,968
Production taxes	2,653			2,121			5,829			3,829
Depreciation and depletion—oil and natural gas	27,038			27,952			51,609			60,278
Depreciation and amortization—other	3,493			6,974			7,330			13,809
Accretion of asset retirement obligations	2,439			1,387			4,848			2,975
Impairment	446			253,629			2,977			363,743
General and administrative	23,769			31,024			43,707			105,302
(Gain) loss on derivative contracts	(23,543		)	7,969			(57,726		)	5,161
Loss on settlement of contract	—			1,092			—			90,184
Other operating (income) expense	(1		)	(103		)	267			3,369
Total expenses	61,503			374,731			109,073			738,618
Income (loss) from operations	23,348			(275,310		)	74,128			(548,865		)
Other (expense) income
Interest expense	(946		)	(41,605		)	(1,885		)	(122,756		)
(Loss) gain on extinguishment of debt	—			(152		)	—			41,179
Reorganization items, net	—			(200,918		)	—			(200,918		)
Other income, net	1,055			2,077			2,025			2,230
Total other income (expense)	109			(240,598		)	140			(280,265		)
Income (loss) before income taxes	23,457			(515,908		)	74,268			(829,130		)
Income tax (benefit) expense	(42		)	3			(39		)	7
Net income (loss)	23,499			(515,911		)	74,307			(829,137		)
Preferred stock dividends	—			5,440			—			16,321
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	23,499		$	(521,351	)	$	74,307		$	(845,458	)
Earnings (loss) per share
Basic	$	0.69		$	(0.73	)	$	2.44		$	(1.20	)
Diluted	$	0.69		$	(0.73	)	$	2.42		$	(1.20	)
Weighted average number of common shares outstanding
Basic	34,076			718,102			30,458			703,943
Diluted	34,138			718,102			30,650			703,943

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

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

(In thousands)



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

Six Months Ended June 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	1,834	—		—	—		—			—			—			—
Common stock issued for debt	14,328	14		—	—		268,765			—			—			268,779
Stock-based compensation	—	—		—	—		11,049			—			—			11,049
Purchase of treasury stock	—	—		—	—		—			(2,891		)	—			(2,891		)
Retirement of treasury stock	—	—		—	—		(2,891		)	2,891			—			—
Net income	—	—		—	—		—			—			74,307			74,307
Balance at June 30, 2017	35,797	$	34	6,442	$	88,381	$	1,035,421		$	—		$	(259,675	)	$	864,161

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)

(In thousands)



	Six Months Ended June 30,
	Successor			Predecessor
	2017			2016
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	74,307		$	(829,137	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Provision for doubtful accounts	—			16,705
Depreciation, depletion and amortization	58,939			74,087
Accretion of asset retirement obligations	4,848			2,975
Impairment	2,977			363,743
Reorganization items, net	—			200,918
Debt issuance costs amortization	195			4,996
Amortization of premiums and discounts on debt	(153		)	2,734
Gain on extinguishment of debt	—			(41,179		)
Gain on debt derivatives	—			(1,324		)
Cash paid for early conversion of convertible notes	—			(33,452		)
(Gain) loss on derivative contracts	(57,726		)	5,161
Cash received on settlement of derivative contracts	2,706			57,970
Loss on settlement of contract	—			90,184
Cash paid on settlement of contract	—			(11,000		)
Stock-based compensation	9,654			7,850
Other	379			(3,252		)
Changes in operating assets and liabilities	7,806			(47,020		)
Net cash provided by (used in) operating activities	103,932			(139,041		)
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(88,904		)	(126,245		)
Acquisition of assets	(48,236		)	(1,397		)
Proceeds from sale of assets	14,756			16,734
Net cash used in investing activities	(122,384		)	(110,908		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	—			488,900
Repayments of borrowings	—			(40,000		)
Debt issuance costs	(1,488		)	(332		)
Purchase of treasury stock	(2,891		)	(41		)
Net cash (used in) provided by financing activities	(4,379		)	448,527
NET (DECREASE) INCREASE IN CASH, CASH EQUIVALENTS and RESTRICTED CASH	(22,831		)	198,578
CASH, CASH EQUIVALENTS and RESTRICTED CASH, beginning of year	174,071			435,588
CASH, CASH EQUIVALENTS and RESTRICTED CASH, end of period	$	151,240		$	634,166
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	$	(8,340	)	$	16,613
Equity issued for debt	$	(268,779	)	$	(4,409	)

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

SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

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

On May 16, 2016, the Company and certain of its direct and indirect subsidiaries (collectively with the Company, the “Debtors”) filed voluntary petitions (the “Bankruptcy Petitions”) for reorganization under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Bankruptcy Court confirmed the Debtors’ joint plan of reorganization (the “Plan”) on September 9, 2016, and the Debtors’ subsequently emerged from bankruptcy on October 4, 2016 (the “Emergence Date”).

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

Interim Financial Statements. The unaudited condensed consolidated financial statements as of December 31, 2016, 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 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 consolidated financial statements included in the 2016 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; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies;

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

Recent Accounting Pronouncements. The Financial Accounting Standards Board “FASB” issued Accounting Standards Update (“ASU”) 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” with the objective of reducing the existing diversity in practice of classification on certain cash receipts and payments in the statement of cash flows. The guidance requires adoption by application of a retrospective method to each period presented. The amendments are effective for the Company on January 1, 2018, with early adoption permitted. The Company adopted the ASU on April 1, 2017. The guidance had no impact on the consolidated financial statements and related disclosures.

The FASB Issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or as a business. The ASU is effective for the Company on January 1, 2018, and amendments should be applied prospectively on and after January 1, 2018. The Company early adopted this ASU for transactions effective after April 1, 2017. The guidance had no impact to the Company’s consolidated financial statements and related disclosures.

Recent Accounting Pronouncements Not Yet Adopted. 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 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. The Company is currently evaluating the effect that the updated standard will have on its consolidated financial statements and related disclosures.

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

The FASB issued ASU 2016-16, “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 does not plan to early adopt and is currently evaluating the effect that the guidance will have on its consolidated financial statements.

The FASB issued ASU 2017-05, “Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic: 610-20): Clarifying the Scope of Asset Derecognition Guidance and the Accounting for Partial Sales of Nonfinancial Assets,” which helps filers determine the guidance applicable for gain/loss recognition subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers. The amendments also clarify that the derecognition of all businesses except those related to conveyances of oil and gas rights or contracts with customers should be accounted for in accordance with the derecognition and deconsolidation guidance in Topic 810, Consolidation. The Company plans to adopt the ASU on January 1, 2018, using the modified retrospective transition method. The Company is currently evaluating the effect that the updated standard will have on its consolidated financial statements and related disclosures.

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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

2. 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 $11.3 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.

3. 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, other current assets, accounts payable and accrued expenses and other current liabilities included in the unaudited condensed consolidated balance sheets approximated fair value at June 30, 2017, and December 31, 2016. As a result, these financial assets and liabilities are not discussed below. The fair values of property, plant and equipment and related impairments, which are calculated using Level 3 inputs, are discussed in Note 4.



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

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

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified in Level 1 and Level 2 of the hierarchy as of June 30, 2017 and December 31, 2016, as described below.

Level 1 Fair Value Measurements

Investments. The fair value of investments, consisting of assets attributable to the Company’s non-qualified deferred compensation plan, is based on quoted market prices. Investments of $6.3 million and $2.8 million are included in other current assets at June 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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

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.

Fair Value - Recurring Measurement Basis

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

June 30, 2017



	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3		Netting(1)			Assets/Liabilities at Fair Value
Assets
Commodity derivative contracts	$	—	$	25,363	$	—	$	(57	)	$	25,306
Investments	6,256		—		—		—			6,256
	$	6,256	$	25,363	$	—	$	(57	)	$	31,562
Liabilities
Commodity derivative contracts	$	—	$	57	$	—	$	(57	)	$	—
	$	—	$	57	$	—	$	(57	)	$	—

December 31, 2016



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

____________________

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

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



	Three Months Ended June 30, 2016			Six Months Ended June 30, 2016
Beginning balance	$	7,281		$	29,355
Gain on derivative holder conversion feature	—			(880		)
Conversions	—			(21,194		)
Write off of derivative holder conversion feature to reorganization items	(7,281		)	(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 six-month periods ended June 30, 2017, and 2016.

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):



	June 30, 2017				December 31, 2016
	Fair Value		Carrying Value		Fair Value		Carrying Value
Convertible Notes	$	—	$	—	$	334,800	$	268,780
Building Note	$	40,461	$	37,679	$	40,608	$	36,528

See Note 5 for additional discussion of the Company’s long-term debt.

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4. Property, Plant and Equipment

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



	June 30, 2017			December 31, 2016
Oil and natural gas properties
Proved	$	934,248		$	840,201
Unproved	111,202			74,937
Total oil and natural gas properties	1,045,450			915,138
Less accumulated depreciation, depletion and impairment	(404,143		)	(353,030		)
Net oil and natural gas properties capitalized costs	641,307			562,108
Land	5,200			5,100
Non-oil and natural gas equipment	158,944			166,010
Buildings and structures	88,503			88,603
Total	252,647			259,713
Less accumulated depreciation and amortization	(10,356		)	(3,889		)
Other property, plant and equipment, net	242,291			255,824
Total property, plant and equipment, net	$	883,598		$	817,932

The Predecessor Company recorded impairments on its oil and natural gas properties of $251.0 million and $359.4 million during the three and six-month periods ended June 30, 2016 as a result of its quarterly full cost ceiling analysis. No full cost ceiling impairments have been recorded in the 2017 period.

In the first quarter of 2017, the Company classified its remaining drilling and oilfield services assets as held for sale in the other current assets line of the unaudited condensed consolidated balance sheet. The net realizable value of the assets was determined to be $4.4 million based on expected sales prices obtained from a third party. The carrying value of these assets exceeded the net realizable value, resulting in impairments of $0.4 million and $3.0 million for the three and six-month periods ended June 30, 2017. The Company disposed of approximately $0.7 million of these assets during the second quarter of 2017 and expects to dispose of the remaining assets during 2017.

Drilling Carry Commitments. Under the terms of an agreement with Repsol E&P USA, Inc. (“Repsol”), the Predecessor Company had agreed to carry Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled in an area of mutual interest. The Predecessor Company incurred $1.0 million and $6.2 million toward this obligation during the three and six-month periods ended June 30, 2016. 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.

5. Long-Term Debt

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

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The Credit Facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all proved reserves included in the most recently delivered reserve report of the Company, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing).

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

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

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

The Company had no amounts outstanding under the Credit Facility at June 30, 2017, and $7.8 million in outstanding letters of credit, which reduce availability under the Credit Facility on a dollar-for-dollar basis.

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

The initial 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.

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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, the Company entered into the Building Note, which had an initial principal amount of $35.0 million. The Building Note was recorded at a fair value of $36.6 million upon implementation of fresh start accounting with the resulting premium to be amortized to interest expense over the term of the Building Note. Interest is payable on the Building Note at 6% per annum for the first year following the Emergence Date, 8% per annum for the second year following the Emergence Date, and 10% thereafter through maturity. Interest costs were paid in kind and added to the Building 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. Net proceeds of $26.8 million received from the sale of the Building Note were subsequently remitted to unsecured creditors on the Emergence Date in accordance with the Plan.

6. Derivatives

Commodity Derivatives

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts, which allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. The Company has not designated any of its derivative contracts as hedges for accounting purposes and records all derivative contracts at fair value with changes in derivative contract fair values recognized in earnings. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Cash settlements and valuation gains and losses on commodity derivative contracts are included in (gain) loss on derivative contracts in the unaudited condensed consolidated statements of operations. Commodity derivative contracts are settled on a monthly or quarterly basis. At June 30, 2017, the Company’s commodity derivative contracts consisted of fixed price swaps under which the Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The Company recorded (gain) loss on commodity derivative contracts of $(23.5) million and $8.0 million for the three-month periods ended June 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $3.3 million and $32.4 million, respectively. The Company recorded (gain) loss on commodity derivative contracts of $(57.7) million and $5.2 million for the six-month periods ended June 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $2.7 million and $58.0 million, respectively. Included in the net cash receipts for the three and six-month periods ended June 30, 2016, are $11.5 million of cash receipts related to certain commodity derivative contracts settled prior to their contractual maturities (“early settlements”).

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Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis in the consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of June 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 in the collateral supporting the Company’s Credit Facility.

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

June 30, 2017



	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral		Net Amount
Assets
Derivative contracts - current	$	17,885	$	(57	)	$	17,828	$	—	$	17,828
Derivative contracts - noncurrent	7,478		—			7,478		—		7,478
Total	$	25,363	$	(57	)	$	25,306	$	—	$	25,306
Liabilities
Derivative contracts - current	$	57	$	(57	)	$	—	$	—	$	—
Total	$	57	$	(57	)	$	—	$	—	$	—

December 31, 2016



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

At June 30, 2017, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

Natural Gas Price Swaps

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Fair Value of Derivatives

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



Type of Contract	Balance Sheet Classification	June 30, 2017			December 31, 2016
Derivative assets
Oil price swaps	Derivative contracts-current	$	15,642		$	—
Natural gas price swaps	Derivative contracts-current	2,243			—
Oil price swaps	Derivative contracts-noncurrent	6,011			—
Natural gas price swaps	Derivative contracts-noncurrent	1,467			—
Derivative liabilities
Oil price swaps	Derivative contracts-current	—			(13,395		)
Natural gas price swaps	Derivative contracts-current	(57		)	(14,143		)
Oil price swaps	Derivative contracts-noncurrent	—			(2,105		)
Natural gas price swaps	Derivative contracts-noncurrent	—			(71		)
Total net derivative contracts		$	25,306		$	(29,714	)

See Note 3 for additional discussion of the fair value measurement of the Company’s derivative contracts.

7. Commitments and Contingencies

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

In addition to the matters described above, the Company is involved in various lawsuits, claims and proceedings which are being handled and defended by the Company in the ordinary course of business.

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

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which depend on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company enters 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 6 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, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2017; however, if oil or natural gas prices decline from current levels, they could have

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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.

8. Equity

Common Stock. On the Emergence Date, the previously issued Predecessor Company common stock was canceled and an aggregate of approximately 18.9 million shares of Common Stock, par value $0.001 per share, was issued to the holders of allowed claims, as defined in the Plan, and approximately 0.4 million shares of Common Stock were reserved for future distributions under the Plan. Additionally, from the Emergence Date through February 9, 2017, voluntary conversions of Convertible Notes resulted in the issuance of approximately 1.0 million shares of Common Stock. The remaining balance of Convertible Notes converted to 14.1 million shares of Common Stock upon refinancing the First Lien Exit Facility. See Note 5 for further discussion of the Convertible Notes.

Warrants. On the Emergence Date, the Company issued approximately 4.9 million Series A Warrants, 4.5 million of which were issued immediately upon emergence, and 2.1 million Series B Warrants, 1.9 million of which were issued immediately upon emergence (the “Warrants”). The Warrants were initially exercisable for one share of Common Stock per Warrant at initial exercise prices of $41.34 and $42.03 per share, respectively, subject to adjustments pursuant to the terms of the Warrants, to certain holders of general unsecured claims as defined in the Plan. The Warrants are exercisable from the Emergence Date until October 4, 2022 and 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 June 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 three and six-month periods ended June 30, 2016 are presented in the unaudited condensed consolidated statement of operations. All outstanding shares of the Predecessor Company's 8.5% and 7.0% convertible perpetual preferred stock were canceled upon Emergence from Chapter 11. See Note 10 for discussion of the Company’s earnings (loss) per share calculation.

9. 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 June 30,					Six Months Ended June 30,
	Successor			Predecessor		Successor			Predecessor
	2017			2016		2017			2016
Current
Federal	$	—		$	—	$	—		$	—
State	(42		)	3		(39		)	7
Total provision	$	(42	)	$	3	$	(39	)	$	7

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. As a result of the significant weight placed on the Company's cumulative negative earnings position, the Company continued to maintain the full valuation allowance against its net deferred tax asset at June 30, 2017. Thus, the Company’s effective tax rate and tax expense for the three and six-month periods ended June 30, 2017, continue to be low.

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Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. As a result of the Chapter 11 reorganization and related transactions, the Company experienced an ownership change within the meaning of IRC Section 382 on October 4, 2016. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the October 4, 2016 ownership change on its tax attributes. Upon filing its 2016 U.S. Federal income tax return, the Company plans to elect an available alternative that does not subject existing tax attributes to an IRC Section 382 limitation. The Company continues to monitor owner shifts that could result in the Company experiencing another ownership change. Should an additional ownership change become likely to occur prior to filing its 2016 U.S. Federal income tax return, the Company will evaluate the remaining available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation, which could result in some or all of the net operating loss carryforwards expiring unused.

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

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10. Earnings (Loss) per Share

As discussed in Note 8, on the Emergence Date, the Predecessor Company’s then-authorized common stock was canceled and the new Common Stock and Warrants were issued.

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



	Net Income (Loss)			Weighted Average Shares	Earnings (Loss) Per Share
	(In thousands, except per share amounts)
Three Months Ended June 30, 2017 (Successor)
Basic earnings per share	$	23,499		34,076	$	0.69
Effect of dilutive securities
Restricted stock awards	—			55
Performance share units	—			7
Diluted earnings per share	$	23,499		34,138	$	0.69


Three Months Ended June 30, 2016 (Predecessor)
Basic loss per share	$	(521,351	)	718,102	$	(0.73	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Diluted loss per share	$	(521,351	)	718,102	$	(0.73	)


Six Months Ended June 30, 2017 (Successor)
Basic earnings per share	$	74,307		30,458	$	2.44
Effect of dilutive securities
Restricted stock awards	—			192
Performance share units(2)	—			—
Diluted earnings per share	$	74,307		30,650	$	2.42


Six Months Ended June 30, 2016 (Predecessor)
Basic loss per share	$	(845,458	)	703,943	$	(1.20	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Diluted loss per share	$	(845,458	)	703,943	$	(1.20	)

____________________


(1)	No incremental shares of potentially dilutive restricted stock awards or units were included for the three and six-month periods ended June 30, 2016 as their effect was antidilutive under the treasury stock method. See Note 11 for discussion of the Company’s share and incentive-based compensation awards.


(2)	No incremental shares of potentially dilutive performance share units were included for the six-month period ended June 30, 2017, as their effect was antidilutive under the treasury stock method. See Note 11 for discussion of the Company’s share and incentive-based compensation awards.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

11. 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 Omnibus Incentive Plan (the “Omnibus Incentive Plan”) became effective.

Persons eligible to receive awards under the Omnibus Incentive Plan include non-employee directors of the Company, employees of the Company or any of its affiliates, and certain consultants and advisors to the Company or any of its affiliates. The types of awards that may be granted under the Omnibus Incentive Plan include stock options, restricted stock, performance awards and other forms of awards granted or denominated in shares of Common Stock, as well as certain cash-based awards. At June 30, 2017, the Company had restricted stock awards, performance share units and performance units outstanding under the Omnibus Incentive Plan.

Restricted Stock Awards. The Successor Company’s restricted stock awards are valued based upon the market value of the Company’s Common Stock on the date of grant. During October 2016, awards for approximately 1.4 million shares of restricted stock were granted under the Omnibus Incentive Plan. These restricted shares will vest over a three-year period. In 2017, awards for approximately 0.6 million shares were granted, which will vest over a period of approximately 2.5 years. The Successor Company recognized share-based compensation expense related to its restricted stock awards of $6.8 million and $10.4 million, net of $0.8 million and $1.3 million capitalized, for the three and six-month periods ended June 30, 2017, respectively. Share-based compensation expense for the six-month period ended June 30, 2017, includes $1.8 million accrued for the accelerated vesting of 0.1 million restricted common stock awards to be processed in the second half of 2017. 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	(368	)	$	22.17
Forfeited / Canceled	(64	)	$	23.70
Unvested restricted shares outstanding at June 30, 2017	1,615		$	23.14

As of June 30, 2017, the Successor Company’s unrecognized compensation cost related to unvested restricted stock awards was $28.9 million. The remaining weighted-average contractual period over which this compensation cost may be recognized is 2.2 years. The Successor Company’s 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. There was no significant activity related to the Company’s outstanding unvested performance share units during the three and six-month periods ended June 30, 2017.

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. There was no significant activity related to the Company’s outstanding unvested performance units during the three and six-month periods ended June 30, 2017.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Predecessor Share-Based Compensation

Restricted Common Stock Awards. The Predecessor Company’s restricted common stock awards generally vested over a four-year period, subject to certain conditions, and were valued based upon the market value of the Company’s common stock on the date of grant. For the three and six-month periods ended June 30, 2016, the Company recognized share-based compensation expense of $2.0 million and $9.4 million, net of $0.5 million and $1.2 million capitalized, respectively. Share-based compensation expense for the six-month period ended June 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 units and performance share units during the three and six-month periods ended June 30, 2016. The following table presents a summary of the Predecessor Company’s unvested restricted stock awards.



	Number of Shares		Weighted-Average Grant Date Fair Value
	(In thousands)
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85
Granted	—		$	—
Vested	(2,458	)	$	5.90
Forfeited / Canceled	(153	)	$	6.25
Unvested restricted shares outstanding at June 30, 2016	3,015		$	3.92

12. Subsequent Events

On July 27, 2017, the Company entered into a $200.0 million drilling participation agreement with a private investment fund (the “Counterparty”) to develop new horizontal wells on the Company’s undeveloped leasehold acreage within the Meramec formation in Major and Woodward Counties in Oklahoma (the “NW STACK”). This is a wellbore only drilling program, and the Company will operate wells developed under this agreement. Pursuant to the terms of the agreement, the Counterparty will fund 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 reversionary hurdles. As a result, the Company will receive a 20% net working interest after funding 10% of the exploration and development costs related to the subject wells. The parties will also have the option to fund a second $100.0 million tranche, subject to mutual agreement.

The drilling participation agreement will become fully effective upon confirmation of certain accounting treatment matters.

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

Introduction

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


•	Overview;


•	Consolidated Results of Operations;


•	Liquidity and Capital Resources;


•	Critical Accounting Policies and Estimates; and


•	Valuation Allowance.

The financial information with respect to the three and six-month periods ended June 30, 2017, and 2016, 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

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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 5 - Long-Term Debt” and “Note 8 - 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 Successor Period statement of operations may not be comparable with the Predecessor Period statement of operations. 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 six-month periods ended June 30, 2017, and 2016 include the following:

•

Total production for the three-month period ended June 30, 2017, was comprised of approximately 27.2% oil, 49.1% natural gas and 23.7% NGLs compared to 28.3% oil, 48.7% natural gas and 23.0% NGLs in the same period of 2016. Total production for the six-month period ended June 30, 2017, was comprised of approximately 27.9% oil, 49.2% natural gas and 22.9% NGLs compared to 29.0% oil, 49.5% natural gas and 21.5% NGLs in the same period of 2016.


•	Increased total rigs drilling to four at June 30, 2017, from two at June 30, 2016.

•

Drilled four and five wells, respectively, in the Mid-Continent during the three and six-month periods ended June 30, 2017, compared to three and ten wells drilled during the same periods in 2016, respectively. Drilled two wells in the North Park Basin during the three and six-month periods ended June 30, 2017, compared to drilling seven and ten wells during the same periods in 2016, respectively.


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

•

Transferred substantially all oil and natural gas properties and midstream assets located in the Piñon field in the WTO and $11.0 million in cash to Occidental in January 2016 in exchange for the release from all past, current and future claims and obligations under an existing 30-year treating agreement 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.

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Recent Transactions

As discussed in “Note 12 - Subsequent Events,” in July 2017, we entered into a $200.0 million drilling participation agreement with a Counterparty to jointly develop new horizontal wells on a wellbore only basis within certain dedicated sections of our undeveloped NW STACK leasehold acreage. If this agreement is declared effective, the Counterparty will pay 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 a result, we will receive a 20% net working interest after funding 10% of the exploration and development costs related to the subject wells. This will allow us to spend minimal additional capital while accelerating the delineation of our position in the NW STACK, adding reserves, realizing further efficiencies and holding additional acreage by production. We will operate all of the wells jointly developed under this agreement and will retain sole discretion as to the number, location and schedule of wells drilled.

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 have increased our 2017 capital expenditures budget to a range between $250.0 million and $260.0 million from the original range of $210.0 million to $220.0 million. The increase in capital expenditures will allow for continued development of these assets in the fourth quarter of 2017 by funding (i) the establishment of two federal units and additional infrastructure in our North Park acreage, and (ii) the acquisition of 3D seismic and core analysis to support our NW STACK drilling program.

Although no impairment was indicated for our oil and natural gas properties during the second quarter of 2017, the current commodity price environment has resulted in the impairment of a significant portion of our oil and natural gas properties over recent reporting periods. The SEC-mandated historical twelve-month unweighted average prices at June 30, 2017, were $45.42 per barrel of oil and $3.01 per Mcf of natural gas. Applying the actual July 1, 2017 and August 1, 2017 benchmark commodities prices, the twelve-month unweighted average prices would be $45.94 per barrel of oil and $3.00 per Mcf of natural gas through August 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. 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”) prices for oil and natural gas during the three and six-month periods ended June 30, 2017, and 2016 are shown in the table below:



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Oil (per Bbl)	$	48.15	$	45.64	$	49.95	$	39.78
Natural gas (per Mcf)	$	3.14	$	2.25	$	3.10	$	2.12

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.

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Oil, Natural Gas and NGL Production and Pricing

Set forth in the table below is production and pricing information for the Successor Company and the Predecessor Company for the three and six-month periods ended June 30, 2017, and 2016.



	Three Months Ended June 30,				Six Months Ended June 30,
	Successor		Predecessor		Successor		Predecessor
	2017		2016		2017		2016
Production data (in thousands)
Oil (MBbls)	1,042		1,408		2,176		3,033
NGL (MBbls)	907		1,144		1,794		2,255
Natural gas (MMcf)	11,267		14,536		23,033		31,045
Total volumes (MBoe)	3,827		4,974		7,809		10,462
Average daily total volumes (MBoe/d)	42.1		54.7		43.1		57.5
Average prices—as reported(1)
Oil (per Bbl)	$	46.04	$	41.70	$	47.68	$	34.33
NGL (per Bbl)	$	14.49	$	13.36	$	15.37	$	12.06
Natural gas (per Mcf)	$	2.08	$	1.49	$	2.23	$	1.57
Total (per Boe)	$	22.09	$	19.23	$	23.40	$	17.21
Average prices—including impact of derivative contract settlements(2)
Oil (per Bbl)	$	49.15	$	56.82	$	49.31	$	49.91
NGL (per Bbl)	$	14.49	$	13.36	$	15.37	$	12.06
Natural gas (per Mcf)	$	2.09	$	1.47	$	2.19	$	1.54
Total (per Boe)	$	22.97	$	23.44	$	23.74	$	21.65

__________________


(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.

The table below presents production by area of operation for the three and six-month periods ended June 30, 2017, and 2016.



	Three Months Ended June 30,						Six Months Ended June 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	3,524	92.1	%	4,703	94.5	%	7,197	92.2	%	9,869	94.3	%
North Park Basin	172	4.5	%	108	2.2	%	345	4.4	%	159	1.5	%
Permian Basin	131	3.4	%	163	3.3	%	267	3.4	%	336	3.2	%
Other	—	—	%	—	—	%	—	—	%	98	1.0	%
Total	3,827	100.0	%	4,974	100.0	%	7,809	100.0	%	10,462	100.0	%

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Revenues

Consolidated revenues for the Successor Period and Predecessor Period are presented in the table below (in thousands):



	Three Months Ended June 30,				Six Months Ended June 30,
	Successor		Predecessor		Successor		Predecessor
	2017		2016		2017		2016
Oil	$	47,978	$	58,710	$	103,760	$	104,125
NGL	13,138		15,287		27,571		27,205
Natural gas	23,430		21,665		51,364		48,707
Other	305		3,759		506		9,716
Total revenues	$	84,851	$	99,421	$	183,201	$	189,753

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 six-month periods ended June 30, 2017, and 2016 are shown in the tables below (in thousands):



	Three Months Ended June 30			Six Months Ended June 30
2016 oil, natural gas and NGL revenues	$	95,662		$	180,037
Change due to production volumes	(23,311		)	(47,532		)
Change due to average prices	12,195			50,190
2017 oil, natural gas and NGL revenues	$	84,546		$	182,695

Revenues from oil, natural gas and NGL sales decreased $11.1 million, or 11.6% for the three-month period ended June 30, 2017, compared to the same period in 2016, largely due to a 1.1 MMBoe decrease in total production, primarily due to natural declines in existing producing wells, as well as a decrease in the number of new wells drilled in 2017 compared to 2016. This decrease was partially offset by an increase in average prices received for our oil, natural gas and NGL production. Revenues from oil, natural gas and NGL sales increased slightly by $2.7 million, or 1.5%, for the six-month period ended June 30, 2017, compared to the same period in 2016, primarily due to an increase in the average prices received for our oil, natural gas, and NGL production, which was largely offset by declines in production as noted above. 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 all oil and natural gas properties and midstream assets located in the Piñon field in the WTO to Occidental in January 2016.

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Expenses



	Three Months Ended June 30,						Six Months Ended June 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Production	$	25,209		$	42,686		$	50,232		$	89,968
Production taxes	2,653			2,121			5,829			3,829
Depreciation and depletion—oil and natural gas	27,038			27,952			51,609			60,278
Depreciation and amortization—other	3,493			6,974			7,330			13,809
Accretion of asset retirement obligations	2,439			1,387			4,848			2,975
Impairment	446			253,629			2,977			363,743
General and administrative	23,769			31,024			43,707			105,302
(Gain) loss on derivative contracts	(23,543		)	7,969			(57,726		)	5,161
Loss on settlement of contract	—			1,092			—			90,184
Other operating (income) expense	(1		)	(103		)	267			3,369
Total expenses	$	61,503		$	374,731		$	109,073		$	738,618

Production expense includes costs associated with our exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production costs per Boe decreased to $6.59 and $6.43 for the three and six-month periods ended June 30, 2017, from $8.58 per Boe and $8.60 per Boe for the same 2016 periods, respectively, primarily due to (i) controlled reductions in expenditures for electricity, chemicals and various other costs, and (ii) the Successor Company’s presentation of transportation costs totaling $6.7 million and $13.7 million as a reduction from revenues for the three and six-month periods ended June 30, 2017, compared to the Predecessor Company’s presentation of transportation costs totaling $8.7 million and $18.2 million as production expenses for the same 2016 periods, respectively.

Depreciation and depletion for our oil and natural gas properties decreased by $0.9 million and $8.7 million for the three and six-month periods ended June 30, 2017, respectively, compared to the same periods in 2016, primarily due to the decrease in production. This decrease in production was partially offset by an increase in the average depreciation and depletion rate per Boe to $7.07 and $6.61 for the three and six-month periods ended June 30, 2017, compared to $5.62 and $5.76 for the same 2016 periods, respectively. The higher rates resulted largely from an increase in anticipated future development costs associated with proved undeveloped reserves added in the fourth quarter of 2016 and the second quarter of 2017, which were partially offset by a full cost ceiling impairment recorded in the fourth quarter of 2016.

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 for the three and six-month periods ended June 30, 2017, reflects the write-down of remaining drilling and services assets classified as held for sale to net realizable value.

Impairment for the three and six-month periods ended June 30, 2016, primarily reflects full cost ceiling limitation impairments of $251.0 million and $359.4 million, respectively, which largely resulted from a decrease in the twelve-month weighted average oil and natural gas prices in the first and second quarters of 2016. No such impairments were necessary in 2017.

General and administrative expenses decreased $7.3 million, or 23.4% for the three-month period ended June 30, 2017, from the same period in 2016 due primarily to (i) a decrease of $10.6 million in professional services costs due to incurring significant consultant and legal fees in the 2016 period in contemplation of the Company’s restructuring, and (ii) a $2.9 million decrease in net salary costs largely resulting from reductions in force during the first and fourth quarters of 2016. These decreases were partially offset by an increase of $4.9 million in severance costs incurred due primarily to the departure of an executive.

General and administrative expenses decreased $61.6 million, or 58.5% for the six-month period ended June 30, 2017, from the same period in 2016 due primarily to (i) a decrease of $23.6 million in professional services costs due to incurring significant consultant and legal fees in the 2016 period in contemplation of the Company’s restructuring, (ii) 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, (iii) a decrease of $13.5 million in severance costs incurred due primarily to a reduction in force that occurred during the first quarter of 2016, and (iv) an $8.6 million decrease in net salary costs largely resulting from reductions in force during the first and fourth quarters of 2016.

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We recorded (gain) loss on commodity derivative contracts of $(23.5) million and $8.0 million for the three-month periods ended June 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $3.3 million and $32.4 million, respectively. We recorded (gain) loss on commodity derivative contracts of $(57.7) million and $5.2 million for the six-month periods ended June 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $2.7 million and $58.0 million, respectively. Included in the net cash receipts for the three and six-month periods ended June 30, 2016 are $11.5 million of cash receipts related to early settlements.

Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded each quarter as a component of operating expenses. Internally, management views the settlement of 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.

Loss on settlement of contract for the six-month period ended June 30, 2016, includes a $78.9 million loss resulting from the termination of a gas treating and CO₂ 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.

Other operating expenses primarily include drilling and oilfield services costs which largely decreased due to discontinuing all remaining drilling and oilfield services operations in 2016.

Other Income (Expense), Taxes and Net Income (Loss)

The Company’s other (expense) income, taxes and net income (loss) for the three and six-month periods ended June 30, 2017, and 2016 are presented in the table below (in thousands).



	Three Months Ended June 30,						Six Months Ended June 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Other (expense) income
Interest expense	$	(946	)	$	(41,605	)	$	(1,885	)	$	(122,756	)
(Loss) gain on extinguishment of debt	—			(152		)	—			41,179
Reorganization items	—			(200,918		)	—			(200,918		)
Other income, net	1,055			2,077			2,025			2,230
Total other income (expense)	109			(240,598		)	140			(280,265		)
Income (loss) before income taxes	23,457			(515,908		)	74,268			(829,130		)
Income tax expense	(42		)	3			(39		)	7
Net income (loss)	$	23,499		$	(515,911	)	$	74,307		$	(829,137	)

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Interest expense for the three and six-month periods ended June 30, 2017, and 2016 consisted of the following:



	Three Months Ended June 30,						Six Months Ended June 30,
	Successor			Predecessor			Successor			Predecessor
	2017			2016			2017			2016
Interest expense
Interest expense on debt	$	1,268		$	40,451		$	2,485		$	119,553
Amortization of debt issuance costs, discounts and premium	(78		)	2,367			(153		)	7,730
Gain on long-term debt holder conversion feature	—			—			—			(1,324		)
Capitalized interest	—			(616		)	—			(2,032		)
Total	1,190			42,202			2,332			123,927
Less: interest income	(244		)	(597		)	(447		)	(1,171		)
Total interest expense	$	946		$	41,605		$	1,885		$	122,756

Total interest expense decreased $40.7 million and $120.9 million for the three and six-month periods ended June 30, 2017, respectively, compared to the same periods in 2016, primarily due to recording interest expense on the Senior Secured Notes, Senior Unsecured Notes, and senior credit facility in the 2016 periods. 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 on extinguishment of debt of $41.2 million for the six-month period ended June 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 5 - 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.

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Liquidity and Capital Resources

As of June 30, 2017, our cash and cash equivalents, excluding restricted cash, were $148.4 million. Additionally, we had approximately $37.7 million in total debt outstanding and $7.8 million in outstanding letters of credit. As of July 31, 2017, the Company had approximately $145.2 million in cash and cash equivalents, excluding restricted cash, an undrawn Credit Facility, and $7.1 million in outstanding letters of credit, which reduce the amount available under the Credit Facility.

Working Capital and Sources and Uses of Cash

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

Our working capital surplus increased to $52.9 million at June 30, 2017, compared to $43.5 million at December 31, 2016, largely due to fluctuations in the timing and amount of collections of receivables and a change in the current derivative liability due to a decrease in oil and gas futures prices compared to contract prices on open contracts at June 30, 2017, as well as contract settlements that occurred in the first six months of 2017. Additionally, $50.0 million in restricted collateral funds were released to us in conjunction with refinancing the First Lien Exit Facility in February 2017, and approximately $47.7 million in cash was used to acquire oil and natural gas properties in the first quarter of 2017.

As noted in “— Outlook,” we have increased our 2017 capital expenditures budget to a range between $250.0 million and $260.0 million from the original range of $210.0 million to $220.0 million. The increase in budgeted capital expenditures is expected to be largely offset by continued declining production costs, an increase in expected production in the second half of 2017, and asset sales through June 30, 2017, resulting in an insignificant impact to future liquidity. Management intends to fund 2017 capital expenditures using cash flow from operations, cash on hand and, if necessary, borrowings under the Credit Facility discussed below.

Cash Flows

Our cash flows from operations, and therefore 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 through June 2017, the month-end NYMEX settled price for oil fluctuated between a high of $60.30 per Bbl in May 2015 and a low of $33.62 per Bbl in January 2016, and the month-end NYMEX settled price for gas fluctuated between a high of $3.93 per MMBtu in January 2017 and a low of $1.71 per MMBtu in March 2016.

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



	Six Months Ended June 30,
	Successor			Predecessor
	2017			2016
Cash flows provided by (used in) operating activities	$	103,932		$	(139,041	)
Cash flows used in investing activities	(122,384		)	(110,908		)
Cash flows (used in) provided by financing activities	(4,379		)	448,527
Net (decrease) increase in cash and cash equivalents	$	(22,831	)	$	198,578

Cash Flows from Operating Activities

The $243.0 million increase in operating cash flows for the six-month period ended June 30, 2017, 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. See “—Consolidated Results of Operations” for further analysis of these changes.

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Cash Flows from Investing Activities

The Company dedicates and expects to continue to dedicate a substantial portion of its capital expenditure program toward the exploration for and production of oil and natural gas. These capital expenditures are necessary to offset inherent declines in production and proved reserves, which is typical in the capital-intensive oil and natural gas industry. During the six-month period ended June 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 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 six-month period ended June 30, 2016, cash flows used in investing activities primarily consisted of capital expenditures for exploration and production activities. Capital expenditures for the six-month periods ended June 30, 2017, and 2016 are summarized on an accrual basis below (in thousands):



	Six Months Ended June 30,
	Successor		Predecessor
	2017		2016
Capital Expenditures
Exploration and production	$	95,234	$	105,049
Other - operating	608		2,190
Other - corporate	1,402		2,393
Capital expenditures, excluding acquisitions	97,244		109,632
Acquisitions	48,236		1,397
Total	$	145,480	$	111,029

Capital expenditures, excluding acquisitions, for exploration and production activities decreased in the 2017 period compared to the 2016 period due primarily to a decrease in drilling activity.

Cash Flows from Financing Activities

Our financing activities used $4.4 million of cash for the six-month period ended June 30, 2017, which consisted of the purchase of common stock upon the vesting of employee share-based compensation awards and deferred financing costs incurred on the Credit Facility. Our financing activities provided approximately $448.5 million during the six-month period ending June 30, 2016, primarily due to net borrowings under the senior credit facility in the first quarter of 2016.

Indebtedness

Long-term debt consists of the following at June 30, 2017 (in thousands):



Credit Facility	$	—
Building Note	37,679
Total Debt	$	37,679

Credit Facility

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


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


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


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


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


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


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


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

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


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

The initial borrowing base under the Credit Facility is $425.0 million and the next borrowing base redetermination is scheduled for October 1, 2017, followed by semiannual borrowing base redeterminations thereafter. The Credit Facility is secured by (i) first-priority mortgages on at least 95% of the PV-9 valuation of all proved reserves included in the most recently delivered reserve report of the Company, (ii) a first-priority perfected pledge of substantially all of the capital stock owned by each credit party and equity interests in the Royalty Trusts that are owned by a credit party and (iii) a first-priority perfected security interest in substantially all the cash, cash equivalents, deposits, securities and other similar accounts, and other tangible and intangible assets of the credit parties (including but not limited to as-extracted collateral, accounts receivable, inventory, equipment, general intangibles, investment property, intellectual property, real property and the proceeds of the foregoing). As described above, the Credit Facility refinanced and thereby replaced the First Lien Exit Facility.

The Credit Facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $25.0 million or more; bankruptcy; judgments involving 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 5 - 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, the Company’s contractual obligations included long-term debt obligations, third-party drilling rig agreements, asset retirement obligations, operating leases and other individually insignificant obligations. Additionally, we have certain financial instruments representing potential commitments that were incurred in the normal course of business to support our operations, including standby letters of credit and surety bonds. The underlying liabilities insured by these instruments are reflected in our balance sheets, where applicable. Therefore, no additional liability is reflected for the letters of credit and surety bonds.

Other than the conversion of the Convertible Notes discussed in “—Overview,” there were no other significant changes in contractual obligations and off-balance sheet arrangements from those reported in the 2016 10-K.

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Critical Accounting Policies and Estimates

For a description of our critical accounting policies and estimates, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2016 Form 10-K. For a discussion of 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 six months of 2017.

Valuation Allowance

Upon emergence from bankruptcy and the application of fresh start accounting, our tax basis in property, plant, and equipment exceeded the book carrying value of our assets. Additionally, we had a significant U.S. Federal net operating loss of approximately $1.3 billion 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 March 31, 2017.

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

We had a presumption of cumulative negative earnings upon emergence from bankruptcy for the purpose of evaluating the need for a valuation allowance and experienced negative earnings for the period from the Emergence Date through December 31, 2016. We had positive earnings for the six-month period ended June 30, 2017, but not in an amount sufficient to result in cumulative positive earnings. The existence of or presumption of cumulative negative earnings is not a definitive factor in a determination to maintain a valuation allowance as all available evidence should be considered, however it is a significant piece of negative evidence in our analysis.

Our revenue, profitability and future growth are substantially dependent upon prevailing and future prices for oil and natural gas. The markets for these commodities continue to be volatile. Relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil and natural gas prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond our control. Due to these factors, we have placed a lower weight on the prospects of future earnings in our overall analysis of the valuation allowance for the period ended June 30, 2017.

In determining whether to maintain the valuation allowance at June 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 ending June 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 ending June 30, 2017. The valuation allowance against our net deferred tax asset at December 31, 2016 was $1.0 billion.

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

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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. 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 pricing 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 limits our ability to enter into derivative transactions to 90% of expected production volumes from estimated proved reserves.

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

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

At June 30, 2017, our open commodity derivative contracts consisted of the following:

Oil Price Swaps

Natural Gas Price Swaps

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 (gain) loss on commodity derivative contracts of $(23.5) million and $8.0 million for the three-month periods ended June 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $3.3 million and $32.4 million, respectively. We recorded (gain) loss on commodity derivative contracts of $(57.7) million and $5.2 million for the six-month periods ended June 30, 2017, and 2016, respectively, which include net cash receipts upon settlement of $2.7 million and $58.0 million, respectively. Included in the net cash receipts for the three and six-month periods ended June 30, 2016, are $11.5 million of cash receipts related to early settlements.

See “Note 6 - Derivatives” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding our commodity derivatives.

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

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

We do not require collateral or other security from counterparties to support derivative instruments. We have master netting agreements with each of our derivative contract counterparties, which allow us to net our derivative assets and liabilities by commodity type with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the commodity derivative contracts. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender under the Credit Facility can be offset against amounts owed, if any, to such counterparty. As of June 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. This variable interest rate on our Credit Facility fluctuates, and exposes us to short-term changes in market interest rates as our interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate. We had no outstanding variable rate debt as of June 30, 2017.

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ITEM 4. Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

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

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PART II. Other Information

ITEM 1. Legal Proceedings

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

In addition to the matter 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.

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 Form 10-K.

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

The following table presents a summary of share repurchases made by the Company during the three-month period ended June 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)
April 1, 2017 — April 30, 2017	—	$	—	N/A	N/A
May 1, 2017 — May 31, 2017	—	$	—	N/A	N/A
June 1, 2017 — June 30, 2017	85,253	$	17.21	N/A	N/A
Total	85,253			—

____________________


(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.

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

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SIGNATURE

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



	SandRidge Energy, Inc.

	By:	/s/ Julian Bott
		Julian Bott Executive Vice President and Chief Financial Officer

Date: August 7, 2017

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EXHIBIT INDEX



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
2.1	Amended Joint Chapter 11 Plan of Reorganization of SandRidge Energy, Inc., et al., dated September 19, 2016	8-A	001-33784	2.1	10/4/2016
3.1	Amended and Restated Certificate of Incorporation of SandRidge Energy, Inc.	8-A	001-33784	3.1	10/4/2016
3.2	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-A	001-33784	3.2	10/4/2016
10.1.6	Form of 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					*