SANDRIDGE ENERGY INC - Quarter Report: 2015 September (Form 10-Q)

Notional (MBbls)

Weighted Average
Fixed Price

October 2015 - December 2015

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________

Form 10-Q

__________________________

(Mark One)



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

For the quarterly period ended September 30, 2015



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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.



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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes 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 October 30, 2015, was 580,044,057.

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References in this report to the “Company” and “SandRidge” mean SandRidge Energy, Inc., including its consolidated subsidiaries and variable interest entities of which it is the primary beneficiary.

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, 2014 (the “2014 Form 10-K”) and in Item 1A of this Quarterly Report.

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SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended September 30, 2015

INDEX



PART I. FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	6
	Condensed Consolidated Statement of Changes in Stockholders' (Deficit) 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	58
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	78
ITEM 4.	Controls and Procedures	81

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	82
ITEM 1A.	Risk Factors	87
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	89
ITEM 6.	Exhibits	89

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PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)



	September 30, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	790,142		$	181,253
Accounts receivable, net	198,205			330,077
Derivative contracts	103,317			291,414
Prepaid expenses	11,308			7,981
Other current assets	6,025			21,193
Total current assets	1,108,997			831,918
Oil and natural gas properties, using full cost method of accounting
Proved	12,302,551			11,707,147
Unproved	260,657			290,596
Less: accumulated depreciation, depletion and impairment	(10,235,369		)	(6,359,149		)
	2,327,839			5,638,594
Other property, plant and equipment, net	507,247			576,463
Derivative contracts	16,249			47,003
Other assets	142,750			165,247
Total assets	$	4,103,082		$	7,259,225

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS - Continued

(In thousands, except per share data)



	September 30, 2015			December 31, 2014
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	445,045		$	683,392
Derivative contracts	369			—
Deferred tax liability	51,126			95,843
Other current liabilities	—			5,216
Total current liabilities	496,540			784,451
Long-term debt	3,936,994			3,195,436
Derivative contracts	326			—
Asset retirement obligations	58,121			54,402
Other long-term obligations	14,371			15,116
Total liabilities	4,506,352			4,049,405
Commitments and contingencies (Note 10)
Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at September 30, 2015 and December 31, 2014; aggregate liquidation preference of $265,000	3			3
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at September 30, 2015 and December 31, 2014; aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value; 1,800,000 shares authorized, 547,718 issued and 546,157 outstanding at September 30, 2015; 800,000 shares authorized, 485,932 issued and 484,819 outstanding at December 31, 2014	542			477
Additional paid-in capital	5,270,225			5,204,024
Additional paid-in capital—stockholder receivable	(2,500		)	(2,500		)
Treasury stock, at cost	(6,876		)	(6,980		)
Accumulated deficit	(6,328,118		)	(3,257,202		)
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,066,721		)	1,937,825
Noncontrolling interest	663,451			1,271,995
Total stockholders’ (deficit) equity	(403,270		)	3,209,820
Total liabilities and stockholders’ (deficit) equity	$	4,103,082		$	7,259,225

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(Unaudited)
Revenues
Oil, natural gas and NGL	$	165,135		$	359,613		$	575,399		$	1,104,835
Drilling and services	4,572			21,348			19,658			57,280
Midstream and marketing	8,838			11,922			26,208			44,706
Other	1,607			1,224			3,802			5,056
Total revenues	180,152			394,107			625,067			1,211,877
Expenses
Production	72,884			82,664			244,158			256,473
Production taxes	3,652			8,380			12,548			24,027
Cost of sales	4,323			15,992			22,034			38,942
Midstream and marketing	6,633			11,405			22,464			40,659
Depreciation and depletion—oil and natural gas	66,501			112,569			266,906			325,021
Depreciation and amortization—other	11,379			14,417			37,234			45,350
Accretion of asset retirement obligations	1,132			1,116			3,323			7,927
Impairment	1,074,588			54			3,647,845			167,966
General and administrative	34,233			24,589			108,764			95,042
Gain on derivative contracts	(42,211		)	(132,575		)	(59,034		)	(4,792		)
Loss (gain) on sale of assets	6,771			(995		)	2,097			(978		)
Total expenses	1,239,885			137,616			4,308,339			995,637
(Loss) income from operations	(1,059,733		)	256,491			(3,683,272		)	216,240
Other (expense) income
Interest expense	(77,000		)	(59,783		)	(213,569		)	(183,689		)
Gain on extinguishment of debt	340,699			—			358,633			—
Other (expense) income, net	(426		)	(273		)	1,208			3,159
Total other income (expense)	263,273			(60,056		)	146,272			(180,530		)
(Loss) income before income taxes	(796,460		)	196,435			(3,537,000		)	35,710
Income tax expense (benefit)	25			(1,064		)	90			(2,131		)
Net (loss) income	(796,485		)	197,499			(3,537,090		)	37,841
Less: net (loss) income attributable to noncontrolling interest	(156,073		)	40,161			(493,243		)	49,733
Net (loss) income attributable to SandRidge Energy, Inc.	(640,412		)	157,338			(3,043,847		)	(11,892		)
Preferred stock dividends	9,114			11,381			27,069			39,144
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(649,526	)	$	145,957		$	(3,070,916	)	$	(51,036	)
(Loss) income per share
Basic	$	(1.23	)	$	0.30		$	(6.14	)	$	(0.11	)
Diluted	$	(1.23	)	$	0.27		$	(6.14	)	$	(0.11	)
Weighted average number of common shares outstanding
Basic	526,388			485,458			500,077			485,194
Diluted	526,388			575,911			500,077			485,194

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

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SANDRIDGE ENERGY, INC.

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

(In thousands)



	SandRidge Energy, Inc. Stockholders
	Convertible Perpetual Preferred Stock			Common Stock				Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	Shares	Amount		Shares		Amount		Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	(Unaudited)
Nine Months Ended September 30, 2015
Balance at December 31, 2014	5,650	$	6	484,819		$	477	$	5,201,524		$	(6,980	)	$	(3,257,202	)	$	1,271,995		$	3,209,820
Distributions to noncontrolling interest owners	—	—		—		—		—			—			—			(115,301		)	(115,301		)
Purchase of treasury stock	—	—		—		—		—			(2,347		)	—			—			(2,347		)
Retirement of treasury stock	—	—		—		—		(2,347		)	2,347			—			—			—
Stock distributions, net of purchases - retirement plans	—	—		(448	)	—		27			104			—			—			131
Stock-based compensation	—	—		—		—		17,251			—			—			—			17,251
Issuance of restricted stock awards, net of cancellations	—	—		1,485		4		(4		)	—			—			—			—
Common stock issued for debt	—	—		36,012		36		35,111			—			—			—			35,147
Net loss	—	—		—		—		—			—			(3,043,847		)	(493,243		)	(3,537,090		)
Convertible perpetual preferred stock dividends	—	—		24,289		25		16,163			—			(27,069		)	—			(10,881		)
Balance at September 30, 2015	5,650	$	6	546,157		$	542	$	5,267,725		$	(6,876	)	$	(6,328,118	)	$	663,451		$	(403,270	)

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Nine Months Ended September 30,
	2015			2014
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(3,537,090	)	$	37,841
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	304,140			370,371
Accretion of asset retirement obligations	3,323			7,927
Impairment	3,647,845			167,966
Debt issuance costs amortization	8,324			7,045
Amortization of discount, net of premium, on long-term debt	1,053			394
Gain on extinguishment of debt	(358,633		)	—
Write off of debt issuance costs	7,108			—
Gain on long-term debt holder conversion feature	(10,146		)	—
Cash paid for early conversion of convertible notes	(2,708		)	—
Gain on derivative contracts	(59,034		)	(4,792		)
Cash received (paid) on settlement of derivative contracts	278,581			(48,816		)
Loss (gain) on sale of assets	2,097			(978		)
Stock-based compensation	15,170			15,853
Other	1,772			488
Changes in operating assets and liabilities	59,084			(157,615		)
Net cash provided by operating activities	360,886			395,684
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(761,905		)	(1,071,465		)
Acquisition of assets	(3,231		)	(16,920		)
Proceeds from sale of assets	35,387			714,294
Net cash used in investing activities	(729,749		)	(374,091		)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	2,190,000			—
Repayments of borrowings	(1,034,466		)	—
Debt issuance costs	(48,021		)	—
Proceeds from sale of royalty trust units	—			22,119
Noncontrolling interest distributions	(115,301		)	(150,440		)
Acquisition of ownership interest	—			(2,730		)
Stock-based compensation excess tax benefit	—			14
Purchase of treasury stock	(3,198		)	(8,278		)
Repurchase of common stock	—			(17,542		)
Dividends paid — preferred	(11,262		)	(45,025		)
Cash paid on settlement of financing derivative contracts	—			(44,128		)
Net cash provided by (used in) financing activities	977,752			(246,010		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	608,889			(224,417		)
CASH AND CASH EQUIVALENTS, beginning of year	181,253			814,663
CASH AND CASH EQUIVALENTS, end of period	$	790,142		$	590,246
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(213,578	)	$	(209,939	)
Cash paid for income taxes	$	(95	)	$	(543	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	160,853		$	(49,072	)
Equity issued for debt	$	(35,147	)	$	—
Preferred stock dividends paid in common stock	$	(16,188	)	$	—

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

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SANDRIDGE ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation

Nature of Business. SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent region of the United States. The Company owns and operates additional interests in west Texas. The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater gathering and disposal system, an electrical transmission system and a drilling and related oil field services business.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned or majority owned subsidiaries and variable interest entities (“VIEs”) for which the Company is the primary beneficiary. Noncontrolling interest represents third-party ownership interests in the Company’s subsidiaries and consolidated VIEs and is included as a component of equity in the consolidated balance sheets and consolidated statement of changes in equity. All significant intercompany accounts and transactions have been eliminated in consolidation.

Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE and the significance of the variable interest, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements. In addition to the VIEs that the Company consolidates, the Company also holds a variable interest in another VIE that is not consolidated as it was determined that the Company is not the entity’s primary beneficiary. The Company monitors both consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 3 for discussion of the Company’s significant associated VIEs.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements as of December 31, 2014 have been derived from the audited financial statements contained in the Company’s 2014 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2014 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 accompanying financial statements include all adjustments, which consist of normal recurring adjustments, necessary to state fairly the information in the Company’s accompanying unaudited condensed consolidated financial statements. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2014 Form 10-K.

Significant Accounting Policies. For a description of the Company’s significant accounting policies, see Note 1 of the consolidated financial statements included in the 2014 Form 10-K.

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 accompanying 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; cash flow estimates used in the valuation of guarantees; 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

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

Recent Accounting Pronouncements. In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” which amends the definition of a discontinued operations to elevate the threshold for a disposal transaction to qualify as a discontinued operation and requires entities to provide additional disclosures for disposal transactions that do not meet the discontinued operations criteria. The guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The guidance was adopted January 1, 2015 and had no impact for the nine-month period ended September 30, 2015.

Recent Accounting Pronouncements Not Yet Adopted. In May 2014, 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 and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Certain of the provisions also amend or supersede existing guidance applicable to the recognition of a gain or loss on transfers of nonfinancial assets that are not an output of an entity’s ordinary activities, including sales of property, plant and equipment and real estate. 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 annual periods beginning after December 15, 2017, and interim periods within that reporting period. Early adoption is permitted, and either a full retrospective or modified approach may be used for adoption. The Company is currently evaluating the effect, if any, that the updated standard will have on its consolidated financial statements and related disclosures.

In August 2014, the FASB issued ASU 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The Company is currently evaluating the effect the guidance will have on its related disclosures.

In February 2015, the FASB issued ASU 2015-02, "Amendments to the Consolidation Analysis," which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a VIE. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. The Company is currently evaluating the effect, if any, that the updated standard will have on its consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs," which requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability, consistent with the presentation of a debt discount. The guidance is effective on a retrospective basis for annual periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. Adoption of the guidance will result in a decrease to the Company's assets and liabilities in the consolidated balance sheets, with no impact to the consolidated statements of operations.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

2. Divestitures

Sale of Gulf of Mexico and Gulf Coast Properties

On February 25, 2014, the Company sold subsidiaries that owned the Company’s Gulf of Mexico and Gulf Coast oil and natural gas properties (the “Gulf Properties”) to Fieldwood Energy, LLC (“Fieldwood”) for approximately $702.6 million, net of working capital adjustments and post-closing adjustments, and Fieldwood’s assumption of approximately $366.0 million of related asset retirement obligations. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss on the sale. See Note 14 for discussion of Fieldwood’s related party affiliation with the Company.

In accordance with the terms of the sale, the Company agreed to guarantee on behalf of Fieldwood certain plugging and abandonment obligations associated with the Gulf Properties for a period of up to one year from the date of closing. The Company recorded a liability equal to the fair value of this guarantee, or $9.4 million, at the time the transaction closed. As of December 31, 2014, the fair value of the guarantee was approximately $5.1 million. See Note 4 for additional discussion of the determination of the guarantee fair value. The Company did not incur any costs as a result of this guarantee and was released from the obligation during the third quarter of 2015. Additionally, Fieldwood maintained, for a period of up to one year from the closing date, restricted deposits held in escrow for plugging and abandonment obligations associated with the Gulf Properties. In the first quarter of 2015, the Company received its share of such deposits, net of any amounts payable to Fieldwood, or $12.0 million, in accordance with the terms of the sale.

The following table presents revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties included in the accompanying unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2014 (in thousands):



	Nine Months Ended September 30, 2014 (1)
Revenues	$	90,920
Expenses	$	63,674

____________________


(1)	Includes revenues and expenses through February 25, 2014, the date of the sale.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

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3. Variable Interest Entities

The Company’s significant associated VIEs, including those for which the Company has determined it is the primary beneficiary and those for which it has determined it is not, are described below.

Royalty Trusts

SandRidge owns beneficial interests in the SandRidge Mississippian Trust I (the “Mississippian Trust I”), the SandRidge Permian Trust (the “Permian Trust”) and SandRidge Mississippian Trust II (the “Mississippian Trust II”) (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”). The Royalty Trusts are considered VIEs due to the lack of voting or similar decision-making rights of the Royalty Trusts’ equity holders regarding activities that have a significant effect on the economic success of the Royalty Trusts. The Company has determined it is the primary beneficiary of the Royalty Trusts as it has (a) the power to direct the activities that most significantly impact the economic performance of the Royalty Trusts through (i) its participation in the creation and structure of the Royalty Trusts, (ii) the manner in which it fulfilled its drilling obligations to the Royalty Trusts as discussed below and (iii) its operation of a majority of the oil and natural gas properties that are subject to the conveyed royalty interests and marketing of the associated production, and (b) the obligation to absorb losses and right to receive residual returns, through its variable interests in the Royalty Trusts, including ownership of common and/or subordinated units, that could potentially be significant to the Royalty Trusts. As a result, the Company consolidates the activities of the Royalty Trusts. The common units of the Royalty Trusts owned by third parties are reflected as noncontrolling interest in the consolidated financial statements.

Common and subordinated units outstanding as of September 30, 2015 and December 31, 2014 for each Royalty Trust are as follows:



	Mississippian Trust I	Permian Trust	Mississippian Trust II
Total outstanding common units(1)	28,000,000	39,375,000	37,293,750
Total outstanding subordinated units(2)	—	13,125,000	12,431,250

____________________


(1)	The Mississippian Trust I’s previously outstanding subordinated units, all of which were held by SandRidge, converted to common units in the third quarter of 2014.


(2)	All outstanding subordinated units are owned by SandRidge.

The Company’s beneficial interests in the Royalty Trusts at September 30, 2015 and December 31, 2014 were as follows:



Mississippian Trust I	26.9	%
Permian Trust	25.0	%
Mississippian Trust II	37.6	%

Royalty Interests. Concurrent with the closing of the Mississippian Trust I and the Permian Trust initial public offerings in 2011 and the closing of the Mississippian Trust II initial public offering in 2012, the Company conveyed certain royalty interests to each Royalty Trust in exchange for (i) the net proceeds of the offering and (ii) common and subordinated units representing beneficial interests in the Royalty Trust. Royalty interests conveyed to the Royalty Trusts were in certain existing wells and wells to be drilled on oil and natural gas properties leased by the Company in defined areas of mutual interest.

Pursuant to the agreements governing the Royalty Trusts, the Mississippian Trust I will terminate in 2030 and the Permian Trust and Mississippian Trust II will terminate in 2031. Upon termination, 50% of the royalty interests conveyed to the Royalty Trust will automatically revert to the Company, and the remaining 50% will be sold, with the proceeds distributed to the Royalty Trust unitholders.

Drilling Obligations. The Company and one of its wholly owned subsidiaries entered into a development agreement with each Royalty Trust upon conveyance of the royalty interests that obligated the Company to drill, or cause to be drilled, a specified number of wells which are also subject to the royalty interests within respective areas of mutual interest by a specified date. One of the Company’s wholly owned subsidiaries also granted to each Royalty Trust a lien on the Company’s interests in the properties where the development wells were to be drilled in order to secure the estimated amount of drilling costs for the Royalty Trust’s interests in the wells. The total amount recoverable by each Royalty Trust under its respective lien was proportionately reduced

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as the Company drilled and completed the associated development wells. The Company fulfilled its drilling obligation to the Mississippian Trust I in the second quarter of 2013, to the Permian Trust in the fourth quarter of 2014 and to the Mississippian Trust II in the first quarter of 2015 and the related liens were automatically released.

Distributions. The Royalty Trusts make quarterly cash distributions to unitholders based on calculated distributable income. Outstanding subordinated units, which constitute 25% of each Royalty Trust’s total outstanding units during the subordination period as described below, are entitled to receive pro rata distributions from the Royalty Trusts each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is no less than the applicable quarterly subordination threshold. If there is not sufficient cash to fund such a distribution on all common units, the distribution made with respect to the subordinated units is reduced or eliminated for such quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on all common units, including common units held by the Company. As holder of the subordinated units, SandRidge is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on all of the Royalty Trust units exceeds the applicable quarterly incentive threshold.

Quarterly distributions declared and paid by the Royalty Trusts during the three and nine-month periods ended September 30, 2015 and 2014 were as follows (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015(1)		2014(2)		2015(1)		2014(2)
Total distributions	$	34,444	$	56,191	$	131,943	$	184,176
Distributions to third-party unitholders	$	30,611	$	47,298	$	115,301	$	150,440

____________________


(1)	Subordination thresholds were not met for the Permian Trust and Mississippian Trust II’s distributions for the three and nine-month periods ended September 30, 2015, resulting in reduced distributions to the Company on its subordinated units for these periods.


(2)	Subordination thresholds were not met for the Mississippian Trust I’s distributions for the three and nine-month periods ended September 30, 2014 and for the Mississippian Trust II’s distributions for the three-month period September 30, 2014, resulting in reduced distributions to the Company on its subordinated units for these periods.

See Note 18 for discussion of the Royalty Trusts’ distributions announced in October 2015.

Following the end of the fourth full calendar quarter subsequent to the Company’s satisfaction of its drilling obligation (the “subordination period”), the subordinated units of each Royalty Trust automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions terminates. In the third quarter of 2014, the Mississippian Trust I’s subordinated units, all of which were held by SandRidge, converted to common units. Beginning with the distribution made in November 2014, all of the Mississippian Trust I’s common units share equally in its distributions. Similarly, as a result of the Company’s fulfillment of its drilling obligations to the Permian Trust and the Mississippian Trust II, the subordinated units of each of these Royalty Trusts will convert to common units on January 1, 2016 and April 1, 2016, respectively, and distributions made in respect of periods thereafter will be shared equally by the Royalty Trusts’ common units. The Company will continue to consolidate the activities of the Royalty Trusts as primary beneficiary subsequent to these conversions due to the Company’s original participation in the design of the Royalty Trusts and continued (a) power to direct the activities that most significantly impact the economic performance of the Royalty Trusts and (b) obligation to absorb losses and right to receive residual returns through its variable interests in the Royalty Trusts, including ownership of common units, that could potentially be significant to the Royalty Trusts.

Loan Commitment. Pursuant to the trust agreements governing the Royalty Trusts, SandRidge has committed to loan funds to each Royalty Trust on an unsecured basis, with terms substantially the same as would be obtained in an arm’s length transaction between SandRidge and an unaffiliated party, if at any time the Royalty Trust’s cash is not sufficient to pay ordinary course administrative expenses as they become due. Any funds loaned may not be used to satisfy indebtedness of the Royalty Trust or to make distributions. There were no amounts outstanding under the loan commitments at September 30, 2015 or December 31, 2014.

Administrative Services. The Company is party to an administrative services agreement with each Royalty Trust, pursuant to which the Company provides certain administrative services to the Royalty Trust, including hedge management services to the Permian Trust and the Mississippian Trust II during the terms of the respective derivatives agreements.

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Derivative Agreements. The Company executed derivatives agreements with each Royalty Trust, pursuant to which the Company provides to the Royalty Trust the economic effects of certain of the Company’s derivative contracts. The tables below present the open oil and natural gas commodity derivative contracts at September 30, 2015 underlying the derivatives agreements with the Mississippian Trust I and Mississippian Trust II. The derivatives agreement with the Permian Trust contained commodity derivative contracts that covered volumes of oil production through March 31, 2015 and is no longer in effect. The combined volume in the tables below reflects the total volume of the Royalty Trusts’ open oil and natural gas commodity derivative contracts.

Oil Price Swaps Underlying the Royalty Trust Derivatives Agreements

Natural Gas Collars Underlying the Royalty Trust Derivatives Agreements



	Notional (MMcf)	Collar Range
October 2015 - December 2015	255	$	4.00	—	$	8.55

See Note 8 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

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Assets and Liabilities. Each Royalty Trust’s assets can be used to settle only that Royalty Trust’s obligations and not other obligations of the Company or another Royalty Trust. The Royalty Trusts’ creditors have no contractual recourse to the general credit of the Company. Although the Royalty Trusts are included in the Company’s consolidated financial statements, the Company’s legal interest in the Royalty Trusts’ assets is limited to its ownership of the Royalty Trusts’ units. At September 30, 2015 and December 31, 2014, $663.5 million and $1.3 billion, respectively, of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets was attributable to the Royalty Trusts. The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at September 30, 2015 and December 31, 2014 consisted of the following (in thousands):



	September 30, 2015			December 31, 2014
Cash and cash equivalents(1)	$	7,702		$	9,387
Accounts receivable, net	6,032			17,660
Derivative contracts	—			6,589
Total current assets	13,734			33,636
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion and impairment(3)	(1,051,186		)	(284,094		)
	274,756			1,041,848
Total assets	$	288,490		$	1,075,484
Accounts payable and accrued expenses	$	952		$	2,852
Total liabilities	$	952		$	2,852

____________________


(1)	Includes $3.0 million held by the trustee at September 30, 2015 and December 31, 2014 as reserves for future general and administrative expenses.


(2)	Investment in royalty interests is included in oil and natural gas properties in the accompanying unaudited condensed consolidated balance sheets.


(3)	Includes cumulative full cost ceiling limitation impairment of $783.5 million and $42.3 million at September 30, 2015 and December 31, 2014, respectively.

See Note 10 for discussion of the Company’s legal proceedings to which the Mississippian Trust I and Mississippian Trust II are also parties.

Sales of Common Units. During the nine-month period ended September 30, 2014, the Company sold Permian Trust common units it owned in a transaction exempt from registration pursuant to Rule 144 under the Securities Act for proceeds of approximately $22.1 million. The sale was accounted for as an equity transaction with no gain or loss recognized. The Company continues to be the primary beneficiary of the Permian Trust after consideration of this transaction and continues to consolidate the activities of the Permian Trust as well as the activities of the Mississippian Trust I and Mississippian Trust II.

Grey Ranch Plant, L.P.

The Company owned a 50% interest in Grey Ranch Plant, L.P. (“GRLP”), which represented a variable interest, prior to one of the Company’s wholly owned subsidiaries acquiring the remaining 50% ownership interest of GRLP from a third party during the first quarter of 2014. The third-party ownership interest in GRLP for the portion of the period prior to the Company's acquisition of the remaining 50% ownership interest in GRLP is reflected in loss attributable to noncontrolling interest owners in the accompanying unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2014. Because the Company was the primary beneficiary and consolidated GRLP, the acquisition of additional ownership interest was recorded as an equity transaction with no gain or loss recognized. Additionally, as a wholly owned subsidiary of the Company, GRLP is no longer considered a VIE for reporting purposes.

Grey Ranch Plant Genpar, LLC

The Company owned a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP, prior to one of the Company’s wholly owned subsidiaries acquiring the remaining 50% ownership interest of Genpar from a third party in the first quarter of 2014. Because the Company was the primary beneficiary and consolidated Genpar, the

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acquisition of additional ownership interest was recorded as an equity transaction with no gain or loss recognized. Additionally, as a wholly owned subsidiary of the Company, Genpar is no longer considered a VIE for reporting purposes.

Piñon Gathering Company, LLC

The Company has a gas gathering and operations and maintenance agreement with Piñon Gathering Company, LLC (“PGC”) through June 30, 2029. Under the gas gathering agreement, the Company is required to compensate PGC for any throughput shortfalls below a required minimum volume. By guaranteeing a minimum throughput, the Company absorbs the risk that lower than projected volumes will be gathered by the gathering system. Therefore, PGC is a VIE. Other than as required under the gas gathering and operations and maintenance agreements, the Company has not provided any support to PGC. While the Company operates the assets of PGC as directed under the operations and management agreement, the member and managers of PGC have the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. Because the Company does not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company is not the primary beneficiary of PGC and does not consolidate the results of PGC’s activities into its financial statements.

Amounts due from and due to PGC as of September 30, 2015 and December 31, 2014 included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):



	September 30, 2015		December 31, 2014
Accounts receivable due from PGC	$	1,034	$	1,141
Accounts payable due to PGC	$	3,955	$	4,163

In October 2015, the Company purchased PGC and terminated the gathering and operations and maintenance agreement. As a wholly-owned subsidiary, PGC will no longer be considered a VIE for reporting purposes. See further discussion at Note 18.

4. Fair Value Measurements

The Company measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the following levels of the fair value hierarchy:



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

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

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

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, considers the market for the Company’s financial assets and liabilities, the associated credit risk and other factors. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. The Company has assets and liabilities classified as Level 1, Level 2 and Level 3 as of September 30, 2015 and December 31, 2014, as described below.

Level 1 Fair Value Measurements

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

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Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

Commodity Derivative Contracts. The fair values of the Company’s natural gas basis swaps are based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness through the use of a discounted cash flow model using non-exchange traded regional pricing information. Additionally, the Company applied a weighted average credit default risk rating factor for its counterparties or gave effect to its credit risk, as applicable, in determining the fair value of these commodity derivative contracts. The significant unobservable input used in the fair value measurement of the Company’s natural gas basis swaps is the estimate of future natural gas basis differentials. Significant increases (decreases) in natural gas basis differentials could result in a significantly higher (lower) fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of the Company’s natural gas basis swaps at September 30, 2015 and December 31, 2014 are included in the table below.



Unobservable Input	Range							Weighted Average			Fair Value
	(Price per Mcf)										(In thousands)
September 30, 2015
Natural gas basis differential forward curve	$	(0.11	)	–	$	(0.31	)	$	(0.20	)	$	(3,436	)
December 31, 2014
Natural gas basis differential forward curve	$	(0.03	)	–	$	(0.38	)	$	(0.29	)	$	350

Long-Term Debt Holder Conversion Feature. In August 2015, the Company issued its 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, “Convertible Senior Unsecured Notes”), each of which contain a conversion option whereby the Convertible Senior Unsecured Notes holders have the option to convert the notes into shares of Company common stock. Further, with respect to any such conversions prior to the second anniversary of the issuance of the Convertible Senior Unsecured Notes, in addition to the shares deliverable upon conversion, holders are entitled to receive an early conversion payment. These conversion features have been identified as embedded derivatives that meet the criteria to be bifurcated from their host contracts, the Convertible Senior Unsecured Notes, and accounted for separately from those notes. The holder conversion features are recorded at fair value each reporting period.

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The fair values of the holder conversion features were determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) recovery rate, (iv) hazard rate and (v) expected volatility. The significant unobservable input used in the fair value measurement of the conversion features is the hazard rate, an estimate of default probability. Significant increases (decreases) in the hazard rate could result in significantly (lower) higher fair value measurement. The significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion options at September 30, 2015 are included in the table below.



Unobservable Input	Range					Weighted Average		Fair Value
								(In thousands)
Long-term debt conversion feature hazard rate	58.6	%	–	62.4	%	60.7	%	$	5,474

See further discussion of the Convertible Senior Unsecured Notes at Note 7.

Guarantee. As discussed in Note 2, the Company guaranteed on Fieldwood’s behalf certain plugging and abandonment obligations associated with the Gulf Properties from the date of closing until the Company was released from the guarantee in third quarter 2015. The fair value of this guarantee was based on the present value of estimated future payments for plugging and abandonment obligations associated with the Gulf Properties, adjusted for the cumulative probability of Fieldwood’s default prior to the Company’s release by the Bureau of Ocean Energy Management from its obligation under the guarantee (3.71% at December 31, 2014). The discount and probability of default rates were based upon inputs that are readily available in the public market, such as historical option adjusted spreads of the Company’s senior notes, which are publicly traded, and historical default rates of publicly traded companies with credit ratings similar to Fieldwood. The significant unobservable input used in the fair value measurement of the guarantee was the estimate of future payments for plugging and abandonment, which was developed based upon third-party quotes and then-current actual costs. Significant increases (decreases) in the estimate of these payments could have resulted in a significantly higher (lower) fair value measurement. The significant unobservable input used in the fair value measurement of the Company’s financial guarantee liability at December 31, 2014 is included in the table below (in thousands).



Unobservable Input
Estimated future payments for plugging and abandonment	$	372,034

Fair Value - Recurring Measurement Basis

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

September 30, 2015



	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	$	—	$	122,307	$	—	$	(2,741	)	$	119,566
Investments	10,444		—		—		—			10,444
	$	10,444	$	122,307	$	—	$	(2,741	)	$	130,010
Liabilities
Commodity derivative contracts	$	—	$	—	$	3,436	$	(2,741	)	$	695
Long-term debt holder conversion feature	—		—		5,474		—			5,474
	$	—	$	—	$	8,910	$	(2,741	)	$	6,169

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December 31, 2014



	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	$	—	$	338,067	$	350	$	—	$	338,417
Investments	11,106		—		—		—		11,106
	$	11,106	$	338,067	$	350	$	—	$	349,523
Liabilities
Guarantee	$	—	$	—	$	5,104	$	—	$	5,104
	$	—	$	—	$	5,104	$	—	$	5,104

____________________

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

Level 3 - Commodity Derivative Contracts. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for commodity derivative contracts during the three and nine-month periods ended September 30, 2015 (in thousands):



Level 3 Fair Value Measurements - Commodity Derivative Contracts	Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015
Beginning balance	$	(2,207	)	$	350
Purchases	—			(2,894		)
Loss on commodity derivative contracts	(1,229		)	(892		)
Ending balance	$	(3,436	)	$	(3,436	)

Losses due to changes in fair value of the Company’s Level 3 commodity derivative contracts have been included in gain on derivative contracts in the accompanying unaudited condensed consolidated statements of operations. There were no outstanding Level 3 commodity derivative contracts at September 30, 2014. See Note 8 for further discussion of the Company’s derivative contracts.

Level 3 - Long-Term Debt Holder Conversion Feature. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for long-term debt holder conversion features during the three and nine-month periods ended September 30, 2015 (in thousands):



Level 3 Fair Value Measurements - Long-Term Debt Holder Conversion Feature
Beginning balance	$	—
Issuances	16,994
Gain on derivative holder conversion feature	(10,146		)
Conversions	(1,374		)
Ending balance	$	5,474

The fair value of the conversion features are determined quarterly with changes in fair value recorded as interest expense.

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Level 3 - Guarantee. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for the guarantee during the three and nine-month periods ended September 30, 2015 and 2014 (in thousands):



	Three Months Ended September 30,						Nine Months Ended September 30,
Level 3 Fair Value Measurements - Guarantee	2015			2014			2015			2014
Beginning balance	$	3,736		$	12,028		$	5,104		$	—
Issuances(1)	—			—			—			9,446
(Gain) loss on guarantee	—			(1,598		)	—			984
Settlements	(3,736		)	—			(5,104		)	—
Ending balance	$	—		$	10,430		$	—		$	10,430

____________________


(1)	For the nine-month period ended September 30, 2014, balance represents the fair value of the guarantee of certain plugging and abandonment obligations on behalf of Fieldwood as of February 25, 2014, the closing date for the sale of the Gulf Properties.

While in effect, the fair value of the guarantee was determined quarterly with changes in fair value recorded as an adjustment to the full cost pool. See Note 2 for discussion of the sale of the Gulf Properties. The fair value of the guarantee as of December 31, 2014 is included in other current liabilities in the accompanying unaudited condensed consolidated balance sheet.

Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the three and nine-month periods ended September 30, 2015 and 2014, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

Fair Value of Financial Instruments

The Company measures the fair value of its 8.75% Senior Secured Notes due 2020 (“Senior Secured Notes”), its 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022, and 7.5% Senior Notes due 2023 (collectively, “Senior Unsecured Notes”) and the Convertible Senior Unsecured Notes using pricing that is readily available in the public market. The Company classifies these inputs as Level 2 in the fair value hierarchy. The estimated fair values and carrying values of the Company’s senior notes at September 30, 2015 and December 31, 2014 were as follows (in thousands):



	September 30, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
8.75% Senior Secured Notes due 2020	$	757,813	$	1,250,000	$	—	$	—
Senior Unsecured Notes
8.75% Senior Notes due 2020(1)	$	95,128	$	401,149	$	303,750	$	445,402
7.5% Senior Notes due 2021(2)	$	218,605	$	996,309	$	752,000	$	1,178,486
8.125% Senior Notes due 2022	$	129,255	$	601,187	$	472,500	$	750,000
7.5% Senior Notes due 2023(3)	$	134,846	$	622,923	$	519,750	$	821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022(4)	$	30,143	$	36,406	$	—	$	—
7.5% Convertible Senior Notes due 2023(5)	$	23,599	$	29,020	$	—	$	—

____________________


(1)	Carrying value is net of $3,649 and $4,598 discount at September 30, 2015 and December 31, 2014, respectively.


(2)	Carrying value includes a premium of $2,652 and $3,486 at September 30, 2015 and December 31, 2014, respectively.


(3)	Carrying value is net of $2,436 and $3,452 discount at September 30, 2015 and December 31, 2014, respectively.


(4)	Carrying value includes holder conversion feature liabilities with fair value of $3,113 and is net of $105,691 discount at September 30, 2015.


(5)	Carrying value includes holder conversion feature liabilities with fair value of $2,361 and is net of $87,412 discount at September 30, 2015.

See Note 7 for discussion of the Company’s long-term debt.

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5. Property, Plant and Equipment

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



	September 30, 2015			December 31, 2014
Oil and natural gas properties
Proved(1)	$	12,302,551		$	11,707,147
Unproved	260,657			290,596
Total oil and natural gas properties	12,563,208			11,997,743
Less accumulated depreciation, depletion and impairment	(10,235,369		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	2,327,839			5,638,594
Land	14,490			16,300
Non-oil and natural gas equipment(2)	431,569			602,392
Buildings and structures(3)	246,847			263,191
Total	692,906			881,883
Less accumulated depreciation and amortization	(185,659		)	(305,420		)
Other property, plant and equipment, net	507,247			576,463
Total property, plant and equipment, net	$	2,835,086		$	6,215,057

____________________


(1)	Includes cumulative capitalized interest of approximately $47.6 million and $38.1 million at September 30, 2015 and December 31, 2014, respectively.


(2)	Includes cumulative capitalized interest of approximately $4.3 million at both September 30, 2015 and December 31, 2014.


(3)	Includes cumulative capitalized interest of approximately $20.3 million and $17.1 million at September 30, 2015 and December 31, 2014, respectively.

Accumulated depreciation, depletion and impairment on oil and natural gas properties includes cumulative full cost ceiling limitation impairment of $7.3 billion and $3.7 billion at September 30, 2015 and December 31, 2014, respectively. The Company reduced the net carrying value of its oil and natural gas properties by $1.0 billion and $3.6 billion during the three and nine-month periods ended September 30, 2015, respectively, and by $164.8 million during the nine-month period ended September 30, 2014, as a result of its quarterly full cost ceiling analyses.

Drilling Assets. During the first quarter of 2015, the Company decided to discontinue all remaining drilling and oilfield services operations in the Permian region and during the second quarter of 2015 classified the related assets having a net book value of approximately $20.0 million, as held for sale, which were included in other current assets at June 30, 2015. The Company disposed of these assets during the third quarter of 2015 and recorded a loss on sale of assets of $3.5 million for the three-month period ended September 30, 2015.

During the third quarter of 2015, the Company evaluated certain drilling assets for impairment based on the Company’s plan for their future use. As a result of these evaluations, the Company recorded an impairment of $19.8 million for the three-month period ended September 30, 2015.

Buildings and Structures. In October 2015, the Company signed an agreement to sell one of its properties located in downtown Oklahoma City, Oklahoma. Because the net book value of the property exceeded the agreed upon sales price, the Company adjusted the carrying value of the property at September 30, 2015 to the agreed upon sales price, resulting in an impairment of $15.4 million for the three-month period ended September 30, 2015.

Drilling Carry Commitments

During the nine-month period ended September 30, 2014, the Company was party to an agreement with a co-working interest party, Repsol E&P USA, Inc.’s (“Repsol”), which contained a carry commitment to fund a portion of the Company’s future drilling, completing and equipping costs within areas of mutual interest. The Company recorded approximately $205.6 million

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for Repsol’s carry during the nine-month period ended September 30, 2014, which reduced the Company’s capital expenditures for the period. Repsol fully funded its carry commitment in the third quarter of 2014.

Under the original agreement, the carry commitment could have been reduced if a certain number of wells were not drilled within the area of mutual interest during a twelve-month period and the Company failed to drill such wells following a proposal by Repsol to drill the wells. During 2013, the Company temporarily reduced its rate of drilling activity. As a result, the Company drilled less than the targeted number of wells for such twelve-month period, which resulted in Repsol having a right to propose additional wells. In the second quarter of 2014, the Company and Repsol amended the agreement to eliminate Repsol’s right to propose such additional wells in exchange for a commitment by the Company to drill 484 net wells in the area of mutual interest between January 1, 2014 and May 31, 2015, subject to delays due to factors beyond the Company’s control. Under the terms of the amended agreement, the Company agreed to carry Repsol’s future drilling and completion costs in the amount of approximately $1.0 million for each well of the 484 commitment that it did not drill, up to a maximum of $75.0 million in carry costs. As of May 31, 2015, the Company had drilled 453 net wells under this arrangement. As a result, the Company will carry a portion of Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled in the future in the area of mutual interest. The Company incurred approximately $3.6 million in costs toward this obligation during the three and nine-month periods ended September 30, 2015. Other than the above, the Company has no carry or drilling obligations to Repsol.

6. Other Assets

Other assets consist of the following (in thousands):



	September 30, 2015		December 31, 2014
Debt issuance costs, net of amortization	$	80,566	$	56,445
Deferred tax asset	51,126		95,843
Investments	10,444		11,106
Other	614		1,853
Total other assets	$	142,750	$	165,247

7. Long-Term Debt

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



	September 30, 2015		December 31, 2014
Senior credit facility	$	—	$	—
8.75% Senior Secured Notes due 2020	1,250,000		—
Senior Unsecured Notes
8.75% Senior Notes due 2020, net of $3,649 and $4,598 discount, respectively	401,149		445,402
7.5% Senior Notes due 2021, including premium of $2,652 and $3,486, respectively	996,309		1,178,486
8.125% Senior Notes due 2022	601,187		750,000
7.5% Senior Notes due 2023, net of $2,436 and $3,452 discount, respectively	622,923		821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $3,113, and net of $105,691 discount	36,406		—
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $2,361, and net of $87,412 discount	29,020		—
Total debt	3,936,994		3,195,436
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,936,994	$	3,195,436

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Senior Credit Facility

The senior secured revolving credit facility (the “senior credit facility”), as amended, is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. Prior to its amendment and restatement on June 10, 2015, the senior credit facility contained certain financial covenants, including maintenance of agreed upon levels for (a) ratio of total debt secured by assets of the Company and certain of its subsidiaries to EBITDA, which was not permitted to exceed 2.25:1.00 at each quarter end, calculated using the last four completed fiscal quarters, (b) ratio of EBITDA to interest expense, which was required to be at least 2.00:1.00 at March 31, 2015 and June 30, 2015, 1.75:1.00 at September 30, 2015, 1.50:1.00 at each quarter end from December 31, 2015 to September 30, 2016, and 2.00:1.00 at December 31, 2016 and thereafter, calculated using the last four completed fiscal quarters, and (c) ratio of current assets to current liabilities, which was required to be at least 1.00:1.00 at each quarter end. A February 2015 amendment temporarily suspended until June 30, 2016 the financial covenant requiring maintenance of certain levels for the ratio of total net debt to EBITDA. For periods after such time, the ratio of total net debt to EBITDA could not exceed 6.25:1.00 at June 30, 2016, 6.00:1.00 at September 30, 2016 and December 31, 2016, 5.50:1.00 at March 31, 2017 and June 30, 2017, 5.00:1.00 at September 30, 2017 and December 31, 2017 and 4.50:1.00 at March 31, 2018 and thereafter, calculated using annualized EBITDA for the fiscal quarter ended June 30, 2016 and the two subsequent fiscal quarters and otherwise calculated using the last four completed fiscal quarters.

The senior credit facility was amended and restated on June 10, 2015 (the “June Amendment”). In connection with the June Amendment, the then-existing financial covenants were replaced. As of then and as of September 30, 2015, the senior credit facility contains financial covenants, including maintenance of agreed upon levels for the (a) ratio of total secured debt under the senior credit facility to EBITDA, which may not exceed 2.00:1.00 at each quarter end and (b) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. For the purpose of the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s commodity derivative contracts are disregarded. The senior credit facility matures on the earlier of March 2, 2020 and 91 days prior to the earliest date of any maturity under or mandatory offer to repurchase the Company’s currently outstanding notes.

Prior and subsequent to the June Amendment, the senior credit facility also contains various covenants that limit the ability of the Company and certain of its subsidiaries to: grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. On August 13, 2015, the senior credit facility was amended to allow the Company to redeem or purchase outstanding Senior Unsecured Notes for up to $200.0 million in cash subject to certain limitations. Additionally, the senior credit facility limits the ability of the Company and certain of its subsidiaries to incur additional indebtedness with certain exceptions. As of and during the three and nine-month periods ended September 30, 2015, the Company was in compliance with all applicable financial covenants under the senior credit facility, including those in effect prior to the June Amendment.

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

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

Borrowings and letter of credit obligations under the senior credit facility may not exceed the lower of the committed amount, which is currently $1.0 billion, or the borrowing base, which is currently $500.0 million and is subject to periodic redeterminations. Prior to the June Amendment, the borrowing base was $900.0 million. This reduction in borrowing base resulted in the write off of approximately $4.9 million of capitalized debt issuance costs. The borrowing base remained unchanged as a

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result of the October 2015 redetermination. The next scheduled borrowing base redetermination is expected to take place in April 2016. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base.

The Company did not draw on the senior credit facility during 2014. The senior credit facility was undrawn at September 30, 2015 and had $11.0 million in outstanding letters of credit, which reduce the availability under the senior credit facility on a dollar-for-dollar basis. At September 30, 2015, the Company had incurred $1.25 billion in junior lien debt subject to an intercreditor agreement as a result of the issuance of Senior Secured Notes in June 2015 as described further below.

Senior Secured Notes

Concurrent with the amendment and restatement of the Company’s senior credit facility discussed above, in June 2015 the Company issued $1.25 billion of Senior Secured Notes. Net proceeds from the issuance were approximately $1.21 billion after deducting offering expenses, a portion of which was used to repay amounts outstanding at that time under the Company’s senior credit facility. The Senior Secured Notes were issued to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S of the Securities Act.

The Company’s Senior Secured Notes bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due upon maturity. The Senior Secured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on a second-priority secured basis by certain of the Company’s wholly owned subsidiaries. See Note 17 for condensed financial information of the subsidiary guarantors. Pursuant to the indenture, the Senior Secured Notes will mature on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019.

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

Debt issuance costs of $39.2 million incurred in connection with the offering of the Senior Secured Notes outstanding at September 30, 2015 are included in other assets in the accompanying unaudited condensed consolidated balance sheet and are being amortized to interest expense over the term of Senior Secured Notes.

Indenture. The indenture governing the Senior Secured Notes contains covenants that restrict the Company’s ability to take a variety of actions, including limitations on the payment of dividends, incurrence of indebtedness, create liens, enter into consolidations or mergers, purchase or redeem stock or subordinated or unsecured indebtedness, certain dispositions and transfers of assets, transactions with related parties, make investments and refinance certain indebtedness. As of and during the three-month period ended September 30, 2015, the Company was in compliance with all of the covenants contained in the indenture governing its outstanding Senior Secured Notes. Because the Senior Secured Notes were not issued until June 2015, the covenants contained therein were not applicable during the three-month period ended March 31, 2015.

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Senior Unsecured Notes

The Company’s Senior Unsecured Notes bear interest at a fixed rate per annum, payable semi-annually, with the principal due upon maturity. Certain of the Senior Unsecured Notes were issued at a discount or a premium. The discount or premium is amortized to interest expense over the term of the respective series of Senior Unsecured Notes. The Senior Unsecured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 17 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $57.6 million incurred in connection with the offerings and subsequent registered exchange offers of the Senior Unsecured Notes outstanding, including the impact of write offs in conjunction with the repurchase and exchange discussed below, are included in other assets in the accompanying unaudited condensed consolidated balance sheets at September 30, 2015 and are being amortized to interest expense over the term of the respective series of Senior Unsecured Notes.

Redemption of Senior Unsecured Notes. During the second quarter of 2015, the Company issued to a holder of its 7.5% Senior Notes due 2021 and 8.125% Senior Notes due 2022, approximately 28.0 million shares of the Company’s common stock in exchange for an aggregate $50.0 million principal amount of the notes ($29.0 million of 7.5% Senior Notes due 2021 and $21.0 million of 8.125% Senior Notes due 2022) and as payment for the interest accrued thereon since the last interest payment date. The exchange resulted in a gain on extinguishment of $17.9 million, which is included in other income on the unaudited condensed consolidated statements of operations for the nine-month period ended September 30, 2015.

Repurchase and Exchange of Senior Unsecured Notes. In August 2015, the Company repurchased $250.0 million of its Senior Unsecured Notes comprised of (i) $29.3 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $111.6 million aggregate principal amount of its 7.5% Senior notes due 2021, (iii) $26.1 million aggregate principal amount of its 8.125% Senior Notes due 2022 and (iv) $83.0 million aggregate principal amount of its 7.5% Senior Notes due 2023, for approximately $94.5 million cash. The repurchase resulted in a gain on extinguishment of $152.0 million, including the write off of $3.2 million of net unamortized debt issuance costs, which is included in other income on the unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2015. In conjunction with the repurchase, the Company also exchanged approximately $275.0 million of its Senior Unsecured Notes for newly-issued Convertible Senior Unsecured Notes, discussed further below.

Indentures. Each of the indentures governing the Company’s Senior Unsecured Notes contains covenants that restrict the Company’s ability to take a variety of actions, including limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and during the three and nine-month periods ended September 30, 2015, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Unsecured Notes.

Convertible Senior Unsecured Notes

In conjunction with the repurchase of Senior Unsecured Notes in August 2015, the Company also exchanged $275.0 million of its Senior Unsecured Notes, comprised of (i) $15.9 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $40.7 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $101.8 million aggregate principal amounts of its 8.125% Senior Notes due 2022 and (iv) $116.6 million aggregate principal amount of its 7.5% Senior Notes due 2023, for (i) $158.4 million aggregate principal amount of newly-issued 8.125% Convertible Senior Notes due 2022 and (ii) $116.6 million aggregate principal amount of newly-issued 7.5% Convertible Senior Notes due 2023. The exchange resulted in a gain on extinguishment of $189.0 million, including the write off of $4.0 million of net unamortized debt issuance costs, which is included in other income on the unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2015.The Convertible Senior Unsecured Notes are guaranteed by the same guarantors that guarantee the Senior Unsecured Notes and are subject to covenants and bear payment terms substantially identical to those of the corresponding series of Senior Unsecured Notes of similar tenor, other than the conversion features, described further below, and the extension of the final maturity by one day. The transactions were determined to be an extinguishment of each of the Senior Unsecured Notes exchanged. As such, the newly-issued Convertible Senior Unsecured Notes were recorded at fair value on the date of issuance, which resulted in a discount that is being amortized to interest expense over the term of the respective series of Convertible Senior Unsecured Notes.

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Debt issuance costs of $5.9 million incurred in connection with the issuance of the Convertible Senior Unsecured Notes, including the impact of write offs in conjunction with the conversions discussed below, are included in other assets in the unaudited condensed consolidated balance sheet at September 30, 2015 and are being amortized to interest expense over the term of the respective series of Convertible Senior Unsecured Notes.

Conversion Features. The Convertible Senior Unsecured Notes are convertible, at the option of the holders, into shares of common stock at any time prior to (i) the fifth business day following the date of a mandatory conversion notice, discussed further below, (ii) with respect to Convertible Senior Unsecured Notes called for redemption, the business day immediately preceding the redemption date or (iii) the business day immediately preceding the maturity date. The conversion rate is approximately 363.6 shares of common stock per $1,000 principal amount of the Convertible Senior Unsecured Notes, subject to customary adjustments. With respect to any conversions prior to the first anniversary of the issuance of the Convertible Senior Unsecured notes, in addition to the shares deliverable upon conversion, holders are entitled to receive an early conversion payment equal to the amount of 18 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. With respect to any conversion subsequent to the first anniversary of the issuance of the Convertible Senior Unsecured Notes, but on or prior to the second anniversary of the issuance of such Convertible Senior Unsecured Notes, holders are entitled to receive an early conversion payment equal to the amount of 12 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. The dilutive effect, if any, of the Convertible Senior Unsecured Notes on the Company’s earnings per share is determined using the if-converted method. See further discussion at Note 13.

See further discussion of the holders’ conversion features, which are embedded derivatives that have been accounted for separately from the Convertible Senior Unsecured Notes, at Note 4 and Note 8.

In addition to the holders’ conversion feature, the Convertible Senior Unsecured Notes contain a provision whereby the Company, subject to compliance with certain conditions, has the right to mandatorily convert the Convertible Senior Unsecured Notes to shares of Company common stock, in whole or in part, at a rate of approximately 363.6 shares of common stock per $1,000 principal amount of Convertible Senior Unsecured Notes, if the volume weighted average price of the Company’s stock exceeds 40.0% of an applicable conversion price of the Convertible Senior Unsecured Notes for a specific period of time. The conversion price threshold, initially set at $1.10, is subject to certain customary adjustments. No early conversion payments will be made upon a mandatory conversion.

Conversions to Common Stock. During the three-month period ended September 30, 2015, holders of $19.4 million aggregate principal amount ($5.8 million net of discount and including holders’ conversion feature) of 8.125% Convertible Senior Notes due 2022 and $2.5 million aggregate principal amount ($0.7 million net of discount and holders’ conversion feature) of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 8.0 million shares of Company common stock and aggregate cash payments of $2.7 million for accrued interest and early conversion payments. The conversions resulted in a loss on extinguishment of debt totaling $0.3 million, including the write off of $0.5 million of net unamortized debt issuance costs, which is included in other income on the unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2015.

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8. Derivatives

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

Commodity Derivatives. The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts, which allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Cash settlements and valuation gains and losses on commodity derivative contracts are included in gain on derivative contracts in the unaudited condensed consolidated statements of operations. Commodity derivative contracts are settled on a monthly or quarterly basis. Derivative assets and liabilities arising from the Company’s commodity derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheets. At September 30, 2015, the Company’s commodity derivative contracts consisted of fixed price swaps, basis swaps and collars, which are described below:



Fixed price swaps	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.

Basis swaps	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for oil or natural gas from a specified delivery point.

Collars	Two-way collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be New York Mercantile Exchange (“NYMEX”) plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract. If the market price is between the ceiling price and purchased put, no payments are due from either party.

Derivatives Agreements with Royalty Trusts. The Company is party to derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts entered into by the Company with third parties. The underlying commodity derivative contracts cover volumes of oil and natural gas production through December 31, 2015 for the Mississippian Trust I and Mississippian Trust II. Under these arrangements, the Company pays the Royalty Trusts amounts it receives from its counterparties in accordance with the underlying contracts, and the Royalty Trusts pay the Company any amounts that the Company is required to pay its counterparties under such contracts. The derivatives agreement with the Permian Trust contained commodity derivative contracts that covered volumes of oil production through March 31, 2015 and is no longer in effect.

In accordance with the terms of the respective derivatives agreements, the Company novated certain of the commodity derivative contracts underlying the derivatives agreements to each of the Permian Trust and the Mississippian Trust II. As a party to these contracts, the Permian Trust and the Mississippian Trust II received payment directly from the counterparty and paid any amounts owed directly to the counterparty. To secure its obligations under the respective derivative contracts novated to it, each of the Permian Trust and the Mississippian Trust II granted the counterparties liens on the royalty interests held by each respective Royalty Trust. As of September 30, 2015, there were no novated derivative contracts outstanding under the derivatives agreements.

All contracts underlying the derivatives agreements with the Royalty Trusts have been included in the Company’s consolidated derivative disclosures. See Note 3 for the Royalty Trusts’ open derivative contracts.

Long-Term Debt Holder Conversion Feature. As discussed further in Note 4 and Note 7, the Convertible Senior Unsecured Notes contain a conversion feature that is exercisable at the holders’ option. This conversion feature has been identified as an embedded derivative as the feature (i) possesses economic characteristics that are not clearly and closely related to the economic characteristics of the host contract, the Convertible Senior Unsecured Notes, and (ii) separate, stand-alone instruments with the

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same terms would qualify as derivative instruments. As such, the holders’ conversion feature has been bifurcated and accounted for separately from the Convertible Senior Unsecured Notes. The holders’ conversion feature is recorded at fair value each reporting period with changes in fair value included in interest expense in the unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2015.

Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of September 30, 2015 and December 31, 2014 on a gross basis without regard to same-counterparty netting (in thousands):



Type of Contract	Balance Sheet Classification	September 30, 2015			December 31, 2014
Derivative assets
Oil price swaps	Derivative contracts-current	$	69,890		$	204,072
Natural gas price swaps	Derivative contracts-current	2,938			29,648
Natural gas basis swaps	Derivative contracts-current	—			350
Oil collars - three way	Derivative contracts-current	32,873			56,289
Natural gas collars	Derivative contracts-current	357			1,055
Oil price swaps	Derivative contracts-noncurrent	13,689			36,288
Oil collars - three way	Derivative contracts-noncurrent	2,560			10,715
Derivative liabilities
Natural gas basis swaps	Derivative contracts-current	(3,110		)	—
Long-term debt holder conversion feature	Long-term debt	(5,474		)	—
Natural gas basis swaps	Derivative contracts-noncurrent	(326		)	—
Total net derivative contracts		$	113,397		$	338,417

See Note 4 for additional discussion of the fair value measurement of the Company’s derivative contracts and Note 7 for discussion of the long-term debt holder conversion feature.

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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 September 30, 2015, the counterparties to the Company’s open commodity derivative contracts consisted of nine financial institutions, four of which are also lenders under the Company’s senior credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as the majority of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the commodity derivative contracts novated by the Company, the Permian Trust and the Mississippian Trust II each gave the counterparties to such contracts a lien on its royalty interests. As of September 30, 2015, the terms of all such novated contracts had expired. 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 senior credit facility (in thousands):

September 30, 2015



	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	106,058	$	(2,741	)	$	103,317	$	—		$	103,317
Derivative contracts - noncurrent	16,249		—			16,249		—			16,249
Total	$	122,307	$	(2,741	)	$	119,566	$	—		$	119,566
Liabilities
Derivative contracts - current	$	3,110	$	(2,741	)	$	369	$	(369	)	$	—
Derivative contracts - noncurrent	326		—			326		(326		)	—
Total	$	3,436	$	(2,741	)	$	695	$	(695	)	$	—

December 31, 2014



	Gross Amounts		Gross Amounts Offset		Amounts Net of Offset		Financial Collateral		Net Amount
Assets
Derivative contracts - current	$	291,414	$	—	$	291,414	$	—	$	291,414
Derivative contracts - noncurrent	47,003		—		47,003		—		47,003
Total	$	338,417	$	—	$	338,417	$	—	$	338,417
Liabilities
Derivative contracts - current	$	—	$	—	$	—	$	—	$	—
Derivative contracts - noncurrent	—		—		—		—		—
Total	$	—	$	—	$	—	$	—	$	—

The Company recorded a gain on commodity derivative contracts of $42.2 million and $132.6 million for the three-month periods ended September 30, 2015 and 2014, respectively, which includes net cash receipts upon settlement of $67.3 million and $3.4 million, respectively. The Company recorded a gain on commodity derivative contracts of $59.0 million and $4.8 million for the nine-month periods ended September 30, 2015 and 2014, respectively, which includes net cash (receipts) payments upon settlement of $(278.6) million and $92.9 million, respectively. Included in the net cash payments for the nine-month period ended September 30, 2014 are $69.6 million of cash payments related to the settlements of commodity derivative contracts with contractual maturities after the period in which they were settled (“early settlements”) primarily as a result of the sale of the Gulf Properties in February 2014.

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At September 30, 2015, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

Natural Gas Price Swaps

Natural Gas Basis Swaps



	Notional (MMcf)	Weighted Average Fixed Price
October 2015 - December 2015	15,640	$	(0.30	)
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
October 2015 - December 2015	1,564	$78.15	$90.03	$103.65
January 2016 - December 2016	2,556	$83.14	$90.00	$100.85

Natural Gas Collars

9. Asset Retirement Obligations

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2014 to September 30, 2015 is as follows (in thousands):



Asset retirement obligations at December 31, 2014	$	54,402
Liability incurred upon acquiring and drilling wells	967
Liability settled or disposed in current period	(571		)
Accretion	3,323
Asset retirement obligations at September 30, 2015	58,121
Less: current portion	—
Asset retirement obligations, net of current	$	58,121

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10. Commitments and Contingencies

Legal Proceedings

On April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP filed suit against the Company and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas and CO₂ produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from the plaintiffs' acreage that results from the treatment of natural gas at Occidental Petroleum Corporation’s (“Occidental”) CO₂ treatment plant in Pecos County, Texas the (“Century Plant”). The plaintiffs seek approximately $45.5 million in actual damages for the period of time between January 2004 and December 2011, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from the plaintiffs' acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and natural gas leases described in the plaintiffs' allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands and seeking approximately $13.0 million in actual damages, inclusive of penalties and interest. On February 5, 2013, the Company received a favorable summary judgment ruling that effectively removes a majority of the plaintiffs' and GLO's claims. On April 29, 2013, the court entered an order allowing for an interlocutory appeal of its summary judgment ruling.

The plaintiffs appealed the rulings to the Texas Court of Appeals in El Paso. On November 19, 2014, that court issued its opinion, which affirmed the trial court’s summary judgment rulings in part, but reversing them in part. The Court of Appeals affirmed the summary judgment rulings in the SandRidge Entities’ favor against the GLO. The court also affirmed the summary judgment rulings in the SandRidge Entities’ favor against Wesley West Minerals, Ltd., on the largest oil and gas lease involved in the case, which accounted for much of the total damages the plaintiffs are claiming. The court reversed certain rulings on other leases, thus deciding those matters for the plaintiffs. The parties have petitioned the Supreme Court of Texas for review of the Court of Appeals’ decision.

The Company intends to continue to defend the remaining issues in the trial court, as well as future appellate proceedings. At the time of the rulings on summary judgment, the lawsuit was still in the discovery stage and, accordingly, an estimate of reasonably possible losses, if any, associated with the remaining causes of action and those rulings reversed by the Court of Appeals cannot be made until all of the facts, circumstances and legal theories relating to such claims and the SandRidge Entities' defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

Between December 2012 and March 2013, seven putative shareholder derivative actions were filed in state and federal court in Oklahoma:


•	Arthur I. Levine v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on December 19, 2012 in the U.S. District Court for the Western District of Oklahoma


•	Deborah Depuy v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Paul Elliot, on Behalf of the Paul Elliot IRA R/O, v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant filed on January 29, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Dale Hefner v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 4, 2013 in the District Court of Oklahoma County, Oklahoma


•	Rocky Romano v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the District Court of Oklahoma County, Oklahoma


•	Joan Brothers v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on February 15, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Lisa Ezell, Jefferson L. Mangus, and Tyler D. Mangus v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on March 22, 2013 in the U.S. District Court for the Western District of Oklahoma

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Each lawsuit identified above was filed derivatively on behalf of the Company and names as defendants current and former directors of the Company. The Hefner lawsuit also names as defendants certain current and former directors and senior executive officers of the Company. All seven lawsuits assert overlapping claims - generally that the defendants breached their fiduciary duties, mismanaged the Company, wasted corporate assets, and engaged in, facilitated or approved self-dealing transactions in breach of their fiduciary obligations. The Depuy lawsuit also alleges violations of federal securities laws in connection with the Company allegedly filing and distributing certain misleading proxy statements. The lawsuits seek, among other relief, injunctive relief related to the Company's corporate governance and unspecified damages.

On April 10, 2013, the U.S. District Court for the Western District of Oklahoma consolidated the Levine, Depuy, Elliot, Brothers, and Ezell actions (the “Federal Shareholder Derivative Litigation”) under the caption “In re SandRidge Energy, Inc. Shareholder Derivative Litigation,” appointed a lead plaintiff and lead counsel, and ordered the lead plaintiff to file a consolidated complaint by May 1, 2013. On June 3, 2013, the Company and the individual defendants filed their respective motions to dismiss the consolidated complaint. On September 11, 2013, the court granted the defendants’ respective motions to dismiss the consolidated complaint without prejudice, and granted plaintiffs leave to file an amended consolidated complaint. The plaintiffs filed an amended consolidated complaint on October 9, 2013, in which plaintiffs allege that: (i) the Company’s former Chief Executive Officer (“CEO”), Tom Ward, breached his fiduciary duties by usurping corporate opportunities, (ii) certain of the Company’s current and former directors breached their fiduciary duties of care, (iii) Mr. Ward and certain of the Company’s current and former directors wasted corporate assets, (iv) certain entities allegedly affiliated with Mr. Ward aided and abetted Mr. Ward’s breaches of fiduciary duties, (v) Mr. Ward and entities allegedly affiliated with Mr. Ward misappropriated the Company’s confidential and proprietary information, and (vi) entities allegedly affiliated with Mr. Ward were unjustly enriched. On November 15, 2013, the Company and the individual defendants filed their respective motions to dismiss the amended consolidated complaint. On September 22, 2014, the court denied the motion to dismiss filed on behalf of the Company and the director defendants. The court also granted in part and denied in part the respective motions to dismiss filed on behalf of the other defendants.

On September 26, 2014, the Board of Directors for the Company formed a Special Litigation Committee (“SLC”), composed of two independent and disinterested Company directors, and delegated absolute and final authority to the SLC to review and investigate the claims alleged by the plaintiffs in the Federal Shareholder Derivative Litigation and in the Hefner action, and to determine whether or how those claims should be asserted on the Company’s behalf. The parties agreed to stay the Hefner action pending the review and investigation by the SLC.

On May 8, 2013, the court stayed the Romano action pending further order of the court. On October 29, 2014, the court granted plaintiff’s application to dismiss the action without prejudice.

On October 7, 2015, the derivative plaintiffs in the Federal Shareholder Derivative Litigation, the Special Litigation Committee, and the individual defendants in the Federal Shareholder Derivative Litigation (Tom Ward, Jim Brewer, Everett Dobson, William Gilliland, Daniel Jordan, Roy Oliver Jr., and Jeffrey Serota), executed a Stipulation of Settlement, which would result in a partial settlement of the Federal Shareholder Derivative Litigation by settling all claims against the individual defendants, subject to certain terms and conditions, including the approval of the court. Under the terms of the proposed partial settlement, the Company would implement or agree to maintain certain corporate governance reforms, and the insurers for the individual defendants would pay $38.0 million to an escrow fund, which would be used to pay certain expenses arising from pending securities litigation and, to the extent funds remain after paying such expenses, would be paid to the Company without any further restrictions on the Company’s use of such funds. The proposed partial settlement expressly provides, among other terms, that the settling defendants deny all allegations of wrongdoing and are entering into the settlement solely to avoid the costs, disruption, uncertainty, and risk of further litigation. The proposed partial settlement would not settle any of the derivative plaintiffs’ claims against non-settling parties WCT Resources, L.L.C., 192 Investments, L.L.C., and TLW Land & Cattle, L.P in the Federal Shareholder Derivative Litigation. On October 9, 2015, the court issued an Order granting preliminary approval to the partial settlement and establishing procedures for notice to shareholders and consideration of any shareholder objections to the partial settlement. The court also set a hearing for final approval of the partial settlement on December 18, 2015.

An estimate of reasonably possible losses associated with the Hefner action cannot be made at this time. The Company has not established any reserves relating to this action.

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and against the same defendants. On March 6, 2013, the court consolidated these two actions under the caption “In re SandRidge Energy, Inc. Securities Litigation” (the “Securities Litigation”) and appointed a lead plaintiff and lead counsel. On July 23, 2013, plaintiffs filed a consolidated amended complaint, which asserts a variety of federal securities claims against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class of (a) purchasers of SandRidge common stock during the period from February 24, 2011 to November 8, 2012, (b) purchasers of common units of the Mississippian Trust I in or traceable to its initial public offering on or about April 12, 2011, and (c) purchasers of common units of the Mississippian Trust II (together with the Mississippian Trust I, the “Mississippian Trusts”) in or traceable to its initial public offering on or about April 23, 2012. The claims are based on allegations that the Company, certain of its current and former officers and directors, and the Mississippian Trusts, among other defendants, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and natural gas reserves, the Company's capital expenditures, and certain transactions entered into by companies allegedly affiliated with the Company's former CEO Tom Ward.

On May 11, 2015, the court dismissed without prejudice plaintiffs’ claims against the Mississippian Trusts and the underwriter defendants. On August 27, 2015, the court dismissed without prejudice plaintiffs’ claims against the Company and the individual current and former officers and directors, and granted plaintiffs leave to file a second amended consolidated complaint.

On October 23, 2015, plaintiffs filed their Second Consolidated Amended Complaint in which plaintiffs assert federal securities claims against the Company and certain of its current and former officers and directors on behalf of a putative class of purchasers of SandRidge common stock during the period between February 24, 2011, and November 8, 2012. The claims are based on allegations that the Company and certain of its current and former officers and directors are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and gas reserves, the Company’s capital expenditures, and certain transactions entered into by companies allegedly affiliated with the Company’s former CEO Tom Ward.

Because the Securities Litigation is in the early stages, an estimate of reasonably possible losses associated with it, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to the Securities Litigation. Each of the Mississippian Trusts has requested that the Company indemnify it for any losses it may incur in connection with the Securities Litigation.

On July 15, 2013, James Hart and 15 other named plaintiffs filed an amended complaint in the United States District Court for the District of Kansas in an action undertaken individually and on behalf of others similarly situated against SandRidge Energy, Inc., SandRidge Operating Company, SandRidge Exploration and Production, LLC (“SandRidge E&P”), SandRidge Midstream, Inc., and Lariat Services, Inc. In their Amended Complaint, plaintiffs allege that the defendants failed to properly calculate overtime pay for the plaintiffs and for other similarly situated current and former employees. The plaintiffs further allege that the defendants required the plaintiffs and other similarly situated current and former employees to engage in work-related activities without pay. The plaintiffs assert claims against the defendants for (i) violations of the Fair Labor Standards Act, (ii) violations of the Kansas Wage Payment Act, (iii) breach of contract, and (iv) fraud, and seek to recover unpaid wages and overtime pay, liquidated damages, statutory penalties, economic damages, compensatory and punitive damages, attorneys’ fees and costs, and both pre- and post-judgment interest.

On October 3, 2013, the plaintiffs filed a Motion for Conditional Collective Action Certification and for Judicial Notice to the Class and a Motion to Toll the Statute of Limitations. On October 11, 2013, the defendants filed a Motion to Dismiss and a Motion to Transfer Venue to the United States District Court for the Western District of Oklahoma.

On April 2, 2014, the court granted the defendants’ Motion to Dismiss and granted plaintiffs leave to file an amended complaint by April 16, 2014, which they did on such date. On July 1, 2014, the court granted plaintiffs’ Motion for Conditional Collective Action Certification and for Judicial Notice to the Class, and denied plaintiffs’ Motion to Toll the Statute of Limitations.

On May 27, 2015, the parties reached an agreement in principle to settle this lawsuit. Pursuant to such agreement, the Company will establish a settlement fund from which to pay participating plaintiffs’ claims as well as plaintiffs’ attorneys’ fees. The proposed settlement agreement is subject to final negotiations between the parties and court approval. During the three-month period ended September 30, 2015, the Company established a $5.1 million reserve for this lawsuit.

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On April 7, 2015, the U.S. Department of Justice notified the Company that it is a target of a grand jury investigation in the Western District of Oklahoma concerning violations of federal antitrust law. The Company is continuing to respond to the government’s requests in connection with the investigation. The Company is unable to predict the outcome of the government's investigation, or any range of loss that could be associated with the resolution of any possible criminal charges or civil claims that may be brought against the Company; however, any governmental action or resolution thereof could be material to the Company. The Company is cooperating with the investigation.

On June 9, 2015, the Duane & Virginia Lanier Trust, individually and on behalf of all others similarly situated, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class of (a) purchasers of common units of the Mississippian Trust I pursuant or traceable to its initial public offering on or about April 7, 2011, and/or at other times during the time period between April 7, 2011, and November 8, 2012 (the “Class Period”), and (b) purchasers of common units of the Mississippian Trust II pursuant or traceable to its initial public offering on or about April 17, 2012, and/or at other times during the Class Period. The claims are based on allegations that the Company, certain of its current and former officers and directors, and the Mississippian Trusts, among other defendants, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and natural gas reserves and the Company's capital expenditures. The Company and the other defendants intend to defend this lawsuit vigorously. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

On July 30, 2015, Barton Gernandt, Jr., individually and on behalf of all others similarly situated, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class comprised of all persons, except the named defendants and their immediate family members, who were participants in, or beneficiaries of, the SandRidge Energy, Inc. 401(k) Plan (the “Plan”) at any time between August 2, 2012, and the present, and whose Plan accounts included investments in SandRidge common stock. The plaintiff purports to bring the action both derivatively on the Plan’s behalf pursuant to ERISA §§ 409 and 502, and as a class action pursuant to Rule 23 of the Federal Rules of Civil Procedure. The plaintiff’s claims are based on allegations that the defendants breached their fiduciary duties owed to the Plan and to the Plan participants by allowing the investment of the Plan’s assets in SandRidge stock when it was otherwise allegedly imprudent to do so based on the financial condition of the Company and the fact the Company’s common stock was artificially inflated because, among other things, the Company materially overstated the amount of oil being produced and the ratio of oil to natural gas in one of its core holdings.

On August 19, 2015, Christina A. Cummings, individually and on behalf of all others similarly situated, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain of its current and former officers, among other defendants, on behalf of a putative class comprised of all participants for whose individual accounts the SandRidge Energy, Inc. 401(k) Plan (the “Plan”) held shares of SandRidge stock from November 8, 2012, to the present, inclusive. The plaintiff purports to bring the action both derivatively on the Plan’s behalf pursuant to ERISA §§ 409 and 502, and as a class action pursuant to Rule 23 of the Federal Rules of Civil Procedure. The plaintiff’s claims are based on allegations that the defendants breached their fiduciary duties owed to the Plan and to the Plan participants by allowing the investment of the Plan’s assets in SandRidge stock when it was otherwise allegedly imprudent to do so based on the financial condition of the Company. On September 10, 2015, the Court consolidated this action with the Gernandt action.

On September 14, 2015, Richard A. McWilliams, individually and on behalf of all others similarly situated, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class comprised of all persons, except the named defendants and their immediate family members, who were participants in, or beneficiaries of, the SandRidge Energy, Inc. 401(k) Plan (the “Plan”) at any time between August 2, 2012, and the present, and whose Plan accounts included investments in SandRidge stock. The plaintiff purports to bring the action both derivatively on the Plan’s behalf pursuant to ERISA §§ 409 and 502, and as a class action pursuant to Rule 23 of the Federal Rules of Civil Procedure. The plaintiff’s claims are based on allegations that the defendants breached their fiduciary duties owed to the Plan and to the Plan participants by allowing the investment of the Plan’s assets in SandRidge stock when it was otherwise allegedly imprudent to do so based on the financial condition of the Company and the fact the Company’s stock was artificially inflated because, among other things, the Company materially overstated the amount of oil being produced and the ratio of oil to natural gas in one of its core holdings. On September 24, 2015, the Court consolidated this action with Gernandt action.

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On October 15, 2015, the Court ordered the plaintiffs in the consolidated Gernandt action to file a consolidated complaint by November 24, 2015.

The Company intends to defend this consolidated lawsuit vigorously. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

In addition to the litigation described above, the Company is a defendant in lawsuits from time to time in the normal course of business. While the results of litigation and claims cannot be predicted with certainty, the Company believes the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, the Company believes the probable final outcome of such matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, cash flows or liquidity.

Treating Agreement Commitment

The Company is party to a 30-year treating agreement with Occidental for the removal of CO₂ from natural gas volumes delivered by the Company. Under the agreement, the Company is required to deliver a total of approximately 3,200 Bcf of CO₂ during the agreement period. The Company is obligated to pay Occidental $0.25 per Mcf to the extent minimum annual CO₂ volume requirements are not met. Through December 31, 2014, the Company had delivered to Occidental 54.7 Bcf of CO2, which is 300.1 Bcf less than the cumulative minimum annual CO2 volume requirements for the same period and had accrued associated annual shortfall penalties of approximately $75.0 million. If such under delivered volumes are not made up with commensurate over deliveries in the future, the Company will be obligated to pay Occidental $0.70 per Mcf (approximately $210.1 million total) in 2041, which amount has not been accrued by the Company as a liability as the Company does not currently believe such payment is probable.

Based upon the quantity of CO2 delivered by the Company during the period from January 1, 2015 through September 30, 2015 and the estimated quantities the Company expects to deliver during the remainder of 2015, the Company accrued estimated annual under delivery penalties ($0.25 per Mcf) of approximately $8.8 million and $26.0 million for the three and nine-month periods ended September 30, 2015, respectively. Based on current projected natural gas production levels, the Company expects to accrue between approximately $31.0 million and $38.0 million during the year ending December 31, 2015 for amounts related to the Company’s anticipated shortfall in meeting its 2015 annual delivery obligations. The Company has not accrued any liability for the $0.70 per Mcf fee (approximately $100.7 million total) that would be due in 2041 if the estimated shortfall for the nine-month period ended September 30, 2015 is not made up in the future as the Company does not currently believe such payment is probable.

If CO₂volumes delivered to Occidental do not materially increase from current levels, the Company will have the right, beginning in 2020, to reduce future minimum annual CO2 volume requirements under the agreement by paying Occidental an amount equal to the present value of $0.70 multiplied by such reduced CO2 volume requirements as designated by the Company. As of September 30, 2015, if the Company were to cease delivering natural gas for processing and made no future CO2 deliveries from such date until 2020, the Company would be required to pay annual delivery shortfall penalties, in the aggregate, of approximately $289.1 million for the contract years 2012 through 2019, which includes $101.0 million for penalties incurred through September 30, 2015. Further, by paying approximately $290.1 million in 2020, which includes the present value of $0.70 multiplied by delivery shortfalls incurred through such date, the Company could adjust the future CO₂ volume requirements to zero. This amount will continue to decrease as future deliveries of CO₂ are made. The Company also may terminate the treating agreement at any time, which would require a termination payment by the Company to Occidental of an amount equal to (a) the present value of $0.70 multiplied by the remaining CO2 volumes required to be delivered under the agreement, plus (b) Occidental’s current net book value of the Century Plant.

The Company has first priority on daily available processing capacity for properly nominated and delivered volumes; however, based on cumulative delivered volumes as of the balance sheet date, if the Company makes no further deliveries from that date until 2025, beginning in 2025 the Century Plant, even if fully utilized, would not have adequate capacity to allow the Company to deliver CO₂ volumes attributable to previously incurred delivery shortfalls at that time.

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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 8 for the Company’s open oil and natural gas derivative contracts.

Production targets contained in certain gathering and treating agreements in effect at September 30, 2015 require the Company to incur capital expenditures or make associated shortfall payments. The Company depends on cash flows from operating activities and, as necessary, borrowings under its senior credit facility to fund its capital expenditures. Additionally, the Company may use proceeds from the issuance of equity and debt securities in the capital markets and from sales or other monetizations of assets to fund its capital expenditures. Based on current cash balances and cash flows from operating activities, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs in 2015; however, if the current depressed oil or natural gas prices persist for a prolonged period or further decline from current levels, they would have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility. See Note 7 for discussion of the financial covenants in the senior credit facility.

On July 23, 2015, the Company received notification from the New York Stock Exchange (“NYSE”) that the price of its common stock had fallen below the NYSE’s listing standard, which requires that the average closing price not be less than $1.00 per share over a period of 30 consecutive trading days. The Company intends to consider available alternatives to cure the stock

price deficiency and return to compliance with the NYSE continued listing requirement. If the Company’s common stock ultimately were to be delisted, it could adversely impact the Company’s ability to generate funds from equity financing.

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11. Equity

Common Stock

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

During the three-month period ended September 30, 2015, the Company issued approximately 8.0 million shares of common stock upon the exercise of conversion options by holders of approximately $21.9 million in par value of the Convertible Senior Unsecured Notes. The Company recorded the issuance of common shares at fair value on the various dates the exchanges occurred. See Note 7 for additional discussion of the Convertible Senior Unsecured Notes transactions.

During the nine-month period ended September 30, 2015, the Company issued approximately 28.0 million shares of common stock in exchange for $50.0 million in Senior Unsecured Notes. See Note 7 for additional discussion of the redemption of Senior Unsecured Notes.

Preferred Stock Dividends

Dividends on the Company’s 8.5% and 7.0% convertible perpetual preferred stock may be paid in cash or with shares of the Company’s common stock at the Company’s election. In the first quarter of 2015, dividends of $11.3 million on the Company’s 8.5% convertible perpetual preferred stock were paid in cash. The remainder of the dividends paid on the Company’s convertible perpetual preferred stock for the nine-month period ended September 30, 2015 were paid by the issuance of common stock as follows:

•

For the nine-month period ended September 30, 2015, the Company paid a semi-annual dividend of $3.50 per share on its 7.0% convertible perpetual preferred stock by issuing approximately 5.7 million shares of common stock. In accordance with the terms governing the 7.0% convertible perpetual preferred stock, for purposes of the dividend payment, the value of each share issued was determined by multiplying (i) the average volume-weighted share price for the 15 trading day period ending April 28, 2015 by (ii) 95%. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, or $2.23 per each of the 3.0 million shares of 7.0% convertible perpetual preferred stock outstanding, that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million. This difference was recorded as a reduction to preferred stock dividends in the unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2015.

•

For the three-month period ended September 30, 2015, the Company paid a semi-annual dividend of $4.25 per share on its 8.5% convertible perpetual preferred stock by issuing approximately 18.6 million shares of common stock. In accordance with the terms governing the 8.5% convertible perpetual preferred stock, for purposes of the dividend payment, the value of each share issued was determined by multiplying (i) the average volume-weighted share price for the 15 trading day period ending July 29, 2015 by (ii) 95%. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, or $3.58 per each of the 2.7 million shares of 8.5% convertible perpetual preferred stock outstanding, that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million. This difference was recorded as a reduction to preferred stock dividends in the unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2015.

All dividend payments for the three and nine-month periods ended September 30, 2014 on the Company’s 8.5%, 6.0% and 7.0% convertible perpetual preferred stock were paid in cash. Additionally, in the fourth quarter of 2014, all outstanding shares of the 6.0% convertible perpetual preferred stock converted automatically into shares of the Company’s common stock at the then-prevailing conversion rate, resulting in the issuance of approximately 18.4 million shares of common stock. The final dividend payment for the 6.0% convertible preferred stock was made during 2014.

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Paid and unpaid dividends included in the calculation of loss applicable to the Company’s common stockholders and the Company’s basic (loss) income per share calculation for the three and nine-month periods ended September 30, 2015 and 2014 are presented in the accompanying unaudited condensed consolidated statements of operations. In the third quarter of 2015, the Company announced the suspension of payment of the semi-annual dividend on shares of its 7.0% convertible perpetual preferred stock.

See Note 13 for discussion of the Company’s loss per share calculation.

Treasury Stock

The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The following table shows the number of shares withheld for taxes and the associated value of those shares for the nine-month periods ended September 30, 2015 and 2014. These shares were accounted for as treasury stock when withheld and then immediately retired.



	Nine Months Ended September 30,
	2015		2014
	(In thousands)
Number of shares withheld for taxes	1,699		1,004
Value of shares withheld for taxes	$	2,347	$	6,281

Stockholder Receivable

The Company is party to a settlement agreement relating to a third-party claim against its former CEO under Section 16(b) of the Securities Exchange Act of 1934, as amended. Based on the nature of the settlement as well as the former CEO’s position as an officer of the Company at the time of the settlement, the receivable is classified as a component of additional paid-in capital in the accompanying unaudited condensed consolidated balance sheets. The remaining amount receivable under the agreement as of September 30, 2015 and December 31, 2014 was $2.5 million and is due in two equal installments in October 2015 and October 2016.

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

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12. Income Taxes

The Company estimates for each interim reporting period 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 for the three and nine-month periods ended September 30, 2015 and 2014 (in thousands):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Current
Federal	$	—	$	(1,160	)	$	—	$	(1,160	)
State	25		96			90		(971		)
	25		(1,064		)	90		(2,131		)
Deferred
Federal	—		—			—		—
State	—		—			—		—
	—		—			—		—
Total provision	25		(1,064		)	90		(2,131		)
Less: income tax provision attributable to noncontrolling interest	19		66			68		236
Total provision attributable to SandRidge Energy, Inc.	$	6	$	(1,130	)	$	22	$	(2,367	)

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 September 30, 2015. Thus the Company’s effective tax rate and tax expense for the three and nine-month periods ended September 30, 2015 continue to be low as a result of the Company not recognizing an income tax benefit associated with its net loss from the same periods.

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. The Company experienced ownership changes within the meaning of IRC Section 382 during 2008 and 2010 that subjected certain of the Company’s tax attributes, including $929.4 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. These limitations could result in a material amount of existing loss carryforwards expiring unused. None of these limitations resulted in a current federal tax liability at September 30, 2015.

At both September 30, 2015 and December 31, 2014, the Company had a liability of approximately $0.1 million for unrecognized tax benefits. The Company does not expect a significant change in its gross unrecognized tax benefits balance within the next twelve months.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2012 to present remain open for federal examination. Additionally, tax years 2005 through 2011 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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13. (Loss) Earnings per Share

The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted loss per share, for the three and nine-month periods ended September 30, 2015 and 2014:



	Net (Loss) Income			Weighted Average Shares	(Loss) Earnings Per Share
	(In thousands, except per share amounts)
Three Months Ended September 30, 2015
Basic loss per share	$	(649,526	)	526,388	$	(1.23	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Convertible preferred stock(2)	—			—
Convertible senior unsecured notes(3)	—			—
Diluted loss per share	$	(649,526	)	526,388	$	(1.23	)
Three Months Ended September 30, 2014
Basic earnings per share	$	145,957		485,458	$	0.30
Effect of dilutive securities
Restricted stock	—			320
Convertible preferred stock	11,381			90,133
Diluted earnings per share	$	157,338		575,911	$	0.27
Nine Months Ended September 30, 2015
Basic loss per share	$	(3,070,916	)	500,077	$	(6.14	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Convertible preferred stock(2)	—			—
Convertible senior unsecured notes(3)	—			—
Diluted loss per share	$	(3,070,916	)	500,077	$	(6.14	)
Nine Months Ended September 30, 2014
Basic loss per share	$	(51,036	)	485,194	$	(0.11	)
Effect of dilutive securities
Restricted stock(4)	—			—
Convertible preferred stock(5)	—			—
Diluted loss per share	$	(51,036	)	485,194	$	(0.11	)

____________________


(1)	No incremental shares of potentially dilutive restricted stock awards or units were included for the three and nine-month periods ended September 30, 2015 as their effect was antidilutive under the treasury stock method.


(2)	Potential common shares related to the Company’s outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.7 million shares for the three and nine-month periods ended September 30, 2015, were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.


(3)	Potential common shares related to the Company’s outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 43.4 million and 14.6 million shares for the three and nine-month periods ended September 30, 2015, respectively, were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.


(4)	Restricted stock awards covering 2.8 million shares for the nine-month period ended September 30, 2014 were excluded from the computation of loss per share because their effect would have been antidilutive.


(5)	Potential common shares related to the Company’s outstanding 8.5%, 6.0% and 7.0% convertible perpetual preferred stock covering 90.1 million shares for the nine-month period ended September 30, 2014, were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

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See Note 7 for discussion of common stock issued in exchange for Senior Unsecured Notes and issuance of the Convertible Senior Unsecured Notes. See Note 11 for discussion of common stock issued in payment of preferred stock dividends.

14. Related Party Transactions

Former Chairman and CEO Severance. Included in other current liabilities and other long-term obligations in the accompanying unaudited condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 are amounts totaling $2.0 million and $3.1 million, respectively, due to the Company’s former Chairman and CEO under the terms of his employment agreement. Such amounts are to be paid in monthly installments through December 2016. See Note 11 for discussion of the stockholder receivable due from the Company’s former Chairman and CEO.

2014 Divestiture. See Note 2 for discussion of the sale of the Gulf Properties to Fieldwood and the Company’s guarantee on behalf of Fieldwood of certain associated plugging and abandonment obligations associated with the Gulf Properties. Fieldwood is a portfolio company of Riverstone Holdings LLC, affiliates of which own a significant number of shares of the Company’s common stock.

Acquisition of Ownership Interest. In March 2014, the Company purchased the additional ownership interest owned by its partner in GRLP and Genpar, which was deemed a related party at the time. See Note 3 for additional discussion.

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15. Share-Based Compensation

The Company issues share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the SandRidge Energy, Inc. 2009 Incentive Plan (the “Plan”). Total share-based compensation expense is measured using the grant date fair value for equity-classified awards and using the fair value at period end for liability-classified awards.

Restricted Common Stock Awards

The Company’s restricted common stock awards generally vest over a four-year period, subject to certain conditions, and are valued based upon the market value of the Company’s common stock on the date of grant. The following table presents a summary of the Company’s unvested restricted stock awards.



	Number of Shares		Weighted- Average Grant Date Fair Value
	(In thousands)
Unvested restricted shares outstanding at December 31, 2014	8,556		$	6.39
Granted	2,928		$	0.88
Vested	(4,887	)	$	4.95
Forfeited / Canceled	(620	)	$	6.39
Unvested restricted shares outstanding at September 30, 2015	5,977		$	4.87

As of September 30, 2015, the Company’s unrecognized compensation cost related to unvested restricted stock awards was $21.9 million. Such cost is expected to be recognized over a weighted-average period of 2.2 years. The Company’s restricted stock awards are equity-classified awards.

Restricted Stock Units

During the nine-month period ended September 30, 2015, the Company granted restricted stock units that vest over a maximum of four years and will be settled in cash, shares of Company common stock or a combination of common stock and cash.

Restricted Stock Units - Settled in Cash or Stock. The following table presents a summary of the Company’s unvested restricted stock units which may be settled in shares of the Company’s common stock, cash or some combination of common stock and cash at the Company’s election. These restricted stock units are liability-classified awards, which vest ratably over a maximum four-year period from the date of grant and were valued at September 30, 2015 based upon the Company’s period end common stock price.



	Number of Units		Fair Value per Unit at September 30, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	11,095
Vested(1)	(873	)
Forfeited / Canceled	(646	)
Unvested units outstanding at September 30, 2015	9,576		$	0.27

____________________

(1) Restricted stock units which vested during the nine-month period ended September 30, 2015 were settled by the issuance of common stock.

As of September 30, 2015, the Company’s unrecognized compensation cost related to the unvested restricted stock units noted above was $1.8 million and is expected to be recognized over a weighted-average period of 1.8 years.

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Restricted Stock Units - Settled in Cash. The following table presents a summary of the Company’s unvested restricted stock units which will be settled in cash at the end of each vesting period for an amount based on the Company’s common stock price as of the vesting date. These restricted stock units are liability-classified awards and vest over a two-year period (40% at the end of the first year and 60% at the end of the second year). The restricted stock units were valued based upon the Company’s period end common stock price, discounted using a credit spread (7.2% at September 30, 2015) that was determined based upon an analysis of the historical option adjusted spread for the Company’s outstanding senior notes and the outstanding long-term debt of comparable companies.



	Number of Units		Fair Value per Unit at September 30, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	3,104
Vested	—
Forfeited / Canceled	(122	)
Unvested units outstanding at September 30, 2015	2,982		$	0.08	–	$	0.23

As of September 30, 2015, the Company’s unrecognized compensation cost related to unvested two-year restricted stock units was $0.2 million. Such cost is expected to be recognized over a weighted-average period of 0.9 years.

Performance Units and Performance Share Units

The Company periodically grants performance units and performance share units to certain members of senior management which vest ratably over a performance period of approximately three years with cash settlements, if any, occurring at the end of the performance period. The value, and ultimate cash settlement, of the performance units is determined based upon the Company’s total shareholder return relative to that of a predetermined peer group over a specific performance period. The Company’s performance units and performance share units are liability-classified awards.

The performance units and performance share units are valued for accounting purposes using a Monte Carlo simulation based on certain assumptions including (i) a volatility assumption based on the historical realized price volatility of the Company’s common stock and the common stock of the predetermined peer group and (ii) a risk-free interest rate based on the U.S. Treasury bond yield for a term commensurate with the approximate remaining vesting period for each grant.

Performance Units. The following table presents a summary of the fair values of the performance units granted during the years ended December 31, 2014 and 2013 and the related assumptions for all outstanding performance units at September 30, 2015 and December 31, 2014.



	September 30, 2015						December 31, 2014
Expected price volatility range	30.7	%	-	148.5		%	26.6	%	-	86.6		%
Weighted-average risk-free interest rate				0.2		%				0.5		%
Weighted-average fair value per unit				$	0.17					$	13.85

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Performance unit activity for the nine-month period ended September 30, 2015 was as follows:



	Number of Performance Units
	(In thousands)
Outstanding at December 31, 2014	66
Granted	—
Forfeited /canceled	—
Outstanding at September 30, 2015	66

Performance period ending December 31, 2015
Vested	22
Unvested	6
Performance period ending December 31, 2016
Vested	15
Unvested	23

Performance Share Units. During the nine-month period ended September 30, 2015, the Company granted performance share units to certain members of senior management. The following table presents a summary of the fair values of the performance share units granted and the related assumptions for all outstanding performance share units at September 30, 2015.



	September 30, 2015
Expected price volatility range	29.8	%	-	116.9		%
Weighted-average risk-free interest rate				0.7		%
Weighted-average fair value per unit				$	0.08

Performance share unit activity for the nine-month period ended September 30, 2015 was as follows:



	Number of Performance Share Units
	(In thousands)
Outstanding at December 31, 2014	—
Granted	2,044
Forfeited /canceled	(151	)
Outstanding at September 30, 2015	1,893

Performance period ending December 31, 2017
Vested	96
Unvested	1,797

Allocation of Share-Based Compensation

Equity compensation provided to employees directly involved in exploration and development activities is capitalized to the Company’s oil and natural gas properties. Equity compensation not capitalized is recognized in general and administrative expenses, production expenses, cost of sales and midstream and marketing expenses in the unaudited condensed consolidated statements of operations. For the three and nine-month periods ended September 30, 2015, the Company recognized share-based compensation expense of $3.6 million and $17.5 million, net of $0.9 million and $3.2 million capitalized, respectively. For the three and nine-month periods ended September 30, 2014, the Company recognized share-based compensation expense of $3.1 million and $18.6 million, net of $1.5 million and $4.5 million capitalized, respectively.

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16. Business Segment Information

The Company has three reportable segments: exploration and production, drilling and oil field services and midstream services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the exploration and production of oil and natural gas properties and includes the activities of the Royalty Trusts. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells and provides various oil field services. The midstream services segment is engaged in the purchasing, gathering, treating and selling of natural gas and coordinates the delivery of electricity to the Company’s exploration and production operations in the Mid-Continent. The All Other columns in the tables below include items not related to the Company’s reportable segments, including the Company’s corporate operations.

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Management evaluates the performance of the Company’s business segments based on income (loss) from operations. Summarized financial information concerning the Company’s segments is shown in the following table (in thousands):



	Exploration and Production(1)			Drilling and Oil Field Services(2)			Midstream Services			All Other (3)			Consolidated Total
Three Months Ended September 30, 2015
Revenues	$	165,134		$	14,754		$	20,812		$	1,608		$	202,308
Inter-segment revenue	—			(10,182		)	(11,974		)	—			(22,156		)
Total revenues	$	165,134		$	4,572		$	8,838		$	1,608		$	180,152
Loss from operations	$	(988,903	)	$	(27,723	)	$	(2,090	)	$	(41,017	)	$	(1,059,733	)
Interest expense	(3		)	—			—			(76,997		)	(77,000		)
Gain on extinguishment of debt	—			—			—			340,699			340,699
Other (expense) income, net	(109		)	3			20			(340		)	(426		)
(Loss) income before income taxes	$	(989,015	)	$	(27,720	)	$	(2,070	)	$	222,345		$	(796,460	)
Capital expenditures(4)	$	106,013		$	259		$	3,719		$	3,306		$	113,297
Depreciation, depletion, amortization and accretion	$	67,652		$	3,966		$	2,984		$	4,410		$	79,012

Three Months Ended September 30, 2014
Revenues	$	359,613		$	51,082		$	31,132		$	1,224		$	443,051
Inter-segment revenue	—			(29,734		)	(19,210		)	—			(48,944		)
Total revenues	$	359,613		$	21,348		$	11,922		$	1,224		$	394,107
Income (loss) from operations	$	275,191		$	(1,155	)	$	(3,218	)	$	(14,327	)	$	256,491
Interest expense	—			—			—			(59,783		)	(59,783		)
Other (expense) income, net	(38		)	(89		)	5			(151		)	(273		)
Income (loss) before income taxes	$	275,153		$	(1,244	)	$	(3,213	)	$	(74,261	)	$	196,435
Capital expenditures(4)	$	435,758		$	3,603		$	14,045		$	14,422		$	467,828
Depreciation, depletion, amortization and accretion	$	113,711		$	6,884		$	2,530		$	4,977		$	128,102

Nine Months Ended September 30, 2015
Revenues	$	575,411		$	56,545		$	63,123		$	3,802		$	698,881
Inter-segment revenue	(12		)	(36,887		)	(36,915		)	—			(73,814		)
Total revenues	$	575,399		$	19,658		$	26,208		$	3,802		$	625,067
Loss from operations	$	(3,554,661	)	$	(39,248	)	$	(9,118	)	$	(80,245	)	$	(3,683,272	)
Interest expense, net	(42		)	—			—			(213,527		)	(213,569		)
Gain on extinguishment of debt	—			—			—			358,633			358,633
Other income, net	1,067			3			33			105			1,208
(Loss) income before income taxes	$	(3,553,636	)	$	(39,245	)	$	(9,085	)	$	64,966		$	(3,537,000	)
Capital expenditures(4)	$	559,515		$	2,732		$	20,400		$	18,405		$	601,052
Depreciation, depletion, amortization and accretion	$	270,292		$	14,726		$	8,457		$	13,988		$	307,463
At September 30, 2015
Total assets	$	2,635,656		$	60,740		$	217,784		$	1,188,902		$	4,103,082

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	Exploration and Production(1)			Drilling and Oil Field Services(2)			Midstream Services			All Other (3)			Consolidated Total
Nine Months Ended September 30, 2014
Revenues	$	1,106,883		$	150,054		$	115,846		$	3,299		$	1,376,082
Inter-segment revenue	(26		)	(92,774		)	(71,405		)	—			(164,205		)
Total revenues	$	1,106,857		$	57,280		$	44,441		$	3,299		$	1,211,877
Income (loss) from operations	$	288,497		$	(6,605	)	$	(6,973	)	$	(58,679	)	$	216,240
Interest income (expense), net	138			—			—			(183,827		)	(183,689		)
Other (expense) income, net	(272		)	(561		)	5			3,987			3,159
Income (loss) before income taxes	$	288,363		$	(7,166	)	$	(6,968	)	$	(238,519	)	$	35,710
Capital expenditures(4)	$	1,056,568		$	10,877		$	25,810		$	27,282		$	1,120,537
Depreciation, depletion, amortization and accretion	$	333,109		$	22,256		$	7,480		$	15,453		$	378,298
At December 31, 2014
Total assets	$	6,273,802		$	115,083		$	219,691		$	650,649		$	7,259,225

____________________


(1)	(Loss) income from operations includes full cost ceiling limitation impairments of $1.0 billion and $3.6 billion for the three and nine-month periods ended September 30, 2015, respectively, and $164.8 million for the nine-month period ended September 30, 2014.


(2)	(Loss) income from operations includes an impairment of $19.8 million on certain drilling assets for the three and nine-month periods ended September 30, 2015 and $3.1 million for certain drilling assets held for sale for the nine-month period ended September 30, 2014.


(3)	(Loss) income from operations for the three and nine-month periods ended September 30, 2015 includes an impairment of $15.4 million on property located in downtown Oklahoma City, Oklahoma. See Note 5.


(4)	On an accrual basis and exclusive of acquisitions.

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17. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. As of September 30, 2015, the subsidiary guarantors, which are 100% owned by the Company, have jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s outstanding Senior Unsecured Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves subsidiary guarantors; and (v) are only released under certain customary circumstances. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes.

Certain of the Company’s wholly owned subsidiaries that were sold in February 2014, as discussed in Note 2, guaranteed the Company’s registered debt. Upon the closing of the sale, these subsidiaries were released from their guarantees. The condensed consolidating financial information in the tables below reflects these subsidiaries’ financial information through the date of the sale.

The following condensed consolidating financial information represents the financial information of SandRidge Energy, Inc., its wholly owned subsidiary guarantors and its non-guarantor subsidiaries, prepared on the equity basis of accounting. The non-guarantor subsidiaries, including consolidated VIEs, majority-owned subsidiaries and certain immaterial wholly owned subsidiaries, are included in the non-guarantors column in the tables below. The financial information may not necessarily be indicative of the financial position, results of operations or cash flows had the subsidiary guarantors operated as independent entities.

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Condensed Consolidating Balance Sheets



	September 30, 2015
	Parent			Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	781,544		$	895	$	7,703	$	—		$	790,142
Accounts receivable, net	7			191,538		6,867		(207		)	198,205
Intercompany accounts receivable	1,021,591			1,345,932		31,568		(2,399,091		)	—
Derivative contracts	—			103,317		9,918		(9,918		)	103,317
Prepaid expenses	—			11,300		8		—			11,308
Other current assets	—			6,025		—		—			6,025
Total current assets	1,803,142			1,659,007		56,064		(2,409,216		)	1,108,997
Property, plant and equipment, net	—			2,525,988		309,098		—			2,835,086
Investment in subsidiaries	3,474,974			7,613		—		(3,482,587		)	—
Derivative contracts	—			16,249		—		—			16,249
Other assets	131,692			16,346		614		(5,902		)	142,750
Total assets	$	5,409,808		$	4,225,203	$	365,776	$	(5,897,705	)	$	4,103,082
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	148,572		$	294,116	$	2,564	$	(207	)	$	445,045
Intercompany accounts payable	1,348,078			1,016,830		34,183		(2,399,091		)	—
Derivative contracts	—			10,287		—		(9,918		)	369
Deferred tax liability	51,126			—		—		—			51,126
Total current liabilities	1,547,776			1,321,233		36,747		(2,409,216		)	496,540
Investment in subsidiaries	985,780			342,035		—		(1,327,815		)	—
Long-term debt	3,942,896			—		—		(5,902		)	3,936,994
Derivative contracts	—			326		—		—			326
Asset retirement obligations	—			58,121		—		—			58,121
Other long-term obligations	77			14,294		—		—			14,371
Total liabilities	6,476,529			1,736,009		36,747		(3,742,933		)	4,506,352
Stockholders’ (Deficit) Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,066,721		)	2,489,194		329,029		(2,818,223		)	(1,066,721		)
Noncontrolling interest	—			—		—		663,451			663,451
Total stockholders’ (deficit) equity	(1,066,721		)	2,489,194		329,029		(2,154,772		)	(403,270		)
Total liabilities and stockholders’ (deficit) equity	$	5,409,808		$	4,225,203	$	365,776	$	(5,897,705	)	$	4,103,082

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(Unaudited)



	December 31, 2014
	Parent(1)		Guarantors(1)(2)		Non-Guarantors(3)		Eliminations(2)(3)			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	170,468	$	1,398	$	9,387	$	—		$	181,253
Accounts receivable, net	7		299,764		30,313		(7		)	330,077
Intercompany accounts receivable	751,376		1,339,152		41,679		(2,132,207		)	—
Derivative contracts	—		284,825		45,043		(38,454		)	291,414
Prepaid expenses	—		7,971		10		—			7,981
Other current assets	—		21,193		—		—			21,193
Total current assets	921,851		1,954,303		126,432		(2,170,668		)	831,918
Property, plant and equipment, net	—		5,137,702		1,077,355		—			6,215,057
Investment in subsidiaries	6,606,198		25,944		—		(6,632,142		)	—
Derivative contracts	—		47,003		—		—			47,003
Other assets	152,286		18,197		666		(5,902		)	165,247
Total assets	$	7,680,335	$	7,183,149	$	1,204,453	$	(8,808,712	)	$	7,259,225
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	151,825	$	526,941	$	4,633	$	(7	)	$	683,392
Intercompany accounts payable	1,365,210		731,103		35,894		(2,132,207		)	—
Derivative contracts	—		38,454		—		(38,454		)	—
Deferred tax liability	95,843		—		—		—			95,843
Other current liabilities	—		5,216		—		—			5,216
Total current liabilities	1,612,878		1,301,714		40,527		(2,170,668		)	784,451
Investment in subsidiaries	928,217		134,013		—		(1,062,230		)	—
Long-term debt	3,201,338		—		—		(5,902		)	3,195,436
Asset retirement obligations	—		54,402		—		—			54,402
Other long-term obligations	77		15,039		—		—			15,116
Total liabilities	5,742,510		1,505,168		40,527		(3,238,800		)	4,049,405
Equity
SandRidge Energy, Inc. stockholders’ equity	1,937,825		5,677,981		1,163,926		(6,841,907		)	1,937,825
Noncontrolling interest	—		—		—		1,271,995			1,271,995
Total equity	1,937,825		5,677,981		1,163,926		(5,569,912		)	3,209,820
Total liabilities and equity	$	7,680,335	$	7,183,149	$	1,204,453	$	(8,808,712	)	$	7,259,225

____________________


(1)	Parent accounts payable and accrued expenses have decreased and intercompany accounts payable have increased by approximately $49.5 million for amounts previously misclassified. Guarantor accounts payable and accrued expenses have increased and intercompany accounts payable have decreased by a corresponding amount.


(2)	Amounts presented as property, plant and equipment have been revised to include approximately $150.4 million previously misclassified as investment in subsidiary.


(3)	Amounts previously misclassified as property, plant and equipment and SandRidge Energy, Inc. stockholders’ equity totaling approximately $150.4 million are now presented as Guarantor property, plant and equipment.

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(Unaudited)

Condensed Consolidating Statements of Operations



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended September 30, 2015
Total revenues	$	—		$	159,502		$	20,650		$	—		$	180,152
Expenses
Direct operating expenses	—			84,577			2,915			—			87,492
General and administrative	48			33,253			932			—			34,233
Depreciation, depletion, amortization and accretion	—			72,384			6,628			—			79,012
Impairment	—			838,331			236,257			—			1,074,588
Gain on derivative contracts	—			(36,761		)	(5,450		)	—			(42,211		)
Loss on sale of assets	—			6,771			—			—			6,771
Total expenses	48			998,555			241,282			—			1,239,885
Loss from operations	(48		)	(839,053		)	(220,632		)	—			(1,059,733		)
Equity earnings from subsidiaries	(904,065		)	(64,546		)	—			968,611			—
Interest expense	(76,998		)	(2		)	—			—			(77,000		)
Gain on extinguishment of debt	340,699			—			—			—			340,699
Other (expense) income, net	—			(464		)	38			—			(426		)
Loss before income taxes	(640,412		)	(904,065		)	(220,594		)	968,611			(796,460		)
Income tax expense	—			—			25			—			25
Net loss	(640,412		)	(904,065		)	(220,619		)	968,611			(796,485		)
Less: net loss attributable to noncontrolling interest	—			—			—			(156,073		)	(156,073		)
Net loss attributable to SandRidge Energy, Inc.	$	(640,412	)	$	(904,065	)	$	(220,619	)	$	1,124,684		$	(640,412	)

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(Unaudited)



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended September 30, 2014
Total revenues	$	—		$	340,563		$	53,544		$	—		$	394,107
Expenses
Direct operating expenses	—			113,774			3,672			—			117,446
General and administrative	57			23,764			768			—			24,589
Depreciation, depletion, amortization and accretion	—			113,649			14,453			—			128,102
Impairment	—			54			—			—			54
Gain on derivative contracts	—			(110,355		)	(22,220		)	—			(132,575		)
Total expenses	57			140,886			(3,327		)	—			137,616
(Loss) income from operations	(57		)	199,677			56,871			—			256,491
Equity earnings from subsidiaries	216,026			16,622			—			(232,648		)	—
Interest expense	(59,783		)	—			—			—			(59,783		)
Other expense, net	—			(273		)	—			—			(273		)
Income before income taxes	156,186			216,026			56,871			(232,648		)	196,435
Income tax (benefit) expense	(1,152		)	—			88			—			(1,064		)
Net income	157,338			216,026			56,783			(232,648		)	197,499
Less: net income attributable to noncontrolling interest	—			—			—			40,161			40,161
Net income attributable to SandRidge Energy, Inc.	$	157,338		$	216,026		$	56,783		$	(272,809	)	$	157,338

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(Unaudited)



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2015
Total revenues	$	—		$	555,613		$	69,462		$	(8	)	$	625,067
Expenses
Direct operating expenses	—			292,526			8,686			(8		)	301,204
General and administrative	165			105,850			2,749			—			108,764
Depreciation, depletion, amortization and accretion	—			280,653			26,810			—			307,463
Impairment	—			2,906,400			741,445			—			3,647,845
Gain on derivative contracts	—			(51,802		)	(7,232		)	—			(59,034		)
Loss (gain) on sale of assets	—			2,101			(4		)	—			2,097
Total expenses	165			3,535,728			772,454			(8		)	4,308,339
Loss from operations	(165		)	(2,980,115		)	(702,992		)	—			(3,683,272		)
Equity earnings from subsidiaries	(3,188,788		)	(209,713		)	—			3,398,501			—
Interest expense	(213,527		)	(42		)	—			—			(213,569		)
Gain on extinguishment of debt	358,633			—			—			—			358,633
Other income, net	—			1,082			126			—			1,208
Loss before income taxes	(3,043,847		)	(3,188,788		)	(702,866		)	3,398,501			(3,537,000		)
Income tax expense	—			—			90			—			90
Net loss	(3,043,847		)	(3,188,788		)	(702,956		)	3,398,501			(3,537,090		)
Less: net loss attributable to noncontrolling interest	—			—			—			(493,243		)	(493,243		)
Net loss attributable to SandRidge Energy, Inc.	$	(3,043,847	)	$	(3,188,788	)	$	(702,956	)	$	3,891,744		$	(3,043,847	)

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(Unaudited)



	Parent			Guarantors			Non-Guarantors		Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2014
Total revenues	$	—		$	1,034,133		$	177,843	$	(99	)	$	1,211,877
Expenses
Direct operating expenses	—			345,809			13,413		(99		)	359,123
General and administrative	277			91,190			3,575		—			95,042
Depreciation, depletion, amortization and accretion	—			333,463			44,835		—			378,298
Impairment	—			125,653			42,313		—			167,966
(Gain) loss on derivative contracts	—			(8,744		)	3,952		—			(4,792		)
Total expenses	277			887,371			108,088		(99		)	995,637
(Loss) income from operations	(277		)	146,762			69,755		—			216,240
Equity earnings from subsidiaries	169,766			19,707			—		(189,473		)	—
Interest (expense) income	(183,827		)	138			—		—			(183,689		)
Other income, net	—			3,159			—		—			3,159
(Loss) income before income taxes	(14,338		)	169,766			69,755		(189,473		)	35,710
Income tax (benefit) expense	(2,446		)	—			315		—			(2,131		)
Net (loss) income	(11,892		)	169,766			69,440		(189,473		)	37,841
Less: net income attributable to noncontrolling interest	—			—			—		49,733			49,733
Net (loss) income attributable to SandRidge Energy, Inc.	$	(11,892	)	$	169,766		$	69,440	$	(239,206	)	$	(11,892	)

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(Unaudited)

Condensed Consolidating Statements of Cash Flows



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2015
Net cash (used in) provided by operating activities	$	(211,762	)	$	441,661		$	90,579		$	40,408		$	360,886
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(761,905		)	—			—			(761,905		)
Other	—			46,841			6			(14,691		)	32,156
Net cash (used in) provided by investing activities	—			(715,064		)	6			(14,691		)	(729,749		)
Cash flows from financing activities
Proceeds from borrowings	2,190,000			—			—			—			2,190,000
Repayments of borrowings	(1,034,466		)	—			—			—			(1,034,466		)
Distributions to unitholders	—			—			(131,941		)	16,640			(115,301		)
Intercompany (advances) borrowings, net	(270,215		)	272,900			(2,685		)	—			—
Other	(62,481		)	—			42,357			(42,357		)	(62,481		)
Net cash provided by (used in) financing activities	822,838			272,900			(92,269		)	(25,717		)	977,752
Net increase (decrease) in cash and cash equivalents	611,076			(503		)	(1,684		)	—			608,889
Cash and cash equivalents at beginning of year	170,468			1,398			9,387			—			181,253
Cash and cash equivalents at end of period	$	781,544		$	895		$	7,703		$	—		$	790,142

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(Unaudited)



	Parent(1)			Guarantors(1)(2)			Non-Guarantors			Eliminations(2)			Consolidated
	(In thousands)
Nine Months Ended September 30, 2014
Net cash (used in) provided by operating activities	$	(209,086	)	$	432,460		$	178,603		$	(6,293	)	$	395,684
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(1,071,465		)	—			—			(1,071,465		)
Proceeds from sale of assets	—			711,547			2,747			—			714,294
Other	—			4,166			1,061			(22,147		)	(16,920		)
Net cash (used in) provided by investing activities	—			(355,752		)	3,808			(22,147		)	(374,091		)
Cash flows from financing activities
Distributions to unitholders	—			—			(184,176		)	33,736			(150,440		)
Intercompany borrowings (advances), net	55,110			(55,224		)	114			—			—
Other	(70,832		)	(20,701		)	1,259			(5,296		)	(95,570		)
Net cash used in financing activities	(15,722		)	(75,925		)	(182,803		)	28,440			(246,010		)
Net (decrease) increase in cash and cash equivalents	(224,808		)	783			(392		)	—			(224,417		)
Cash and cash equivalents at beginning of year	805,505			1,013			8,145			—			814,663
Cash and cash equivalents at end of period	$	580,697		$	1,796		$	7,753		$	—		$	590,246

____________________

(1)

Net cash (used in) provided by operating activities for the Parent has decreased to correctly exclude $382.7 million in intercompany transactions, with a corresponding increase for Guarantors for this same line item. In addition, Intercompany borrowings (advances), net for the Parent has increased to correctly include approximately $382.7 million of intercompany transactions, with a corresponding decrease for Guarantors for the same line item. The corrections did not result in any changes to consolidated net cash provided by operating activities or net cash used in financing activities.

(2)

Other investing activities for the Guarantor has increased to correctly exclude $150.4 million in noncontrolling interest distributions, with a corresponding decrease for Eliminations for this same line item. In addition, other financing activities for the Guarantor, has decreased to correctly exclude $150.4 million of noncontrolling interest distributions, with a corresponding increase for Eliminations for the same line item. The corrections did not result in any changes to consolidated net cash (used in) provided by investing activities or net cash used in financing activities.

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(Unaudited)

18. Subsequent Events

Royalty Trust Distributions. On October 29, 2015, the Royalty Trusts announced quarterly distributions for the three-month period ended September 30, 2015. The following distributions are expected to be paid on or before November 27, 2015 to holders of record as of the close of business on November 13, 2015 (in thousands):



Royalty Trust	Total Distribution		Amount Distributed to Third-Party Unitholders
Mississippian Trust I	$	8,528	$	6,236
Permian Trust	9,844		9,844
Mississippian Trust II	8,317		6,924
Total	$	26,689	$	23,004

Purchase of PGC. In October 2015, the Company purchased PGC for $48.0 million cash and $78.0 million of Senior Secured Notes. PGC’s assets consist of approximately 370 miles ofgathering lines that support the Company’s production in the Piñon field in West Texas. The transaction resulted in the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. The Company expects to recognize a loss on the termination of the gathering contract, however, is currently obtaining further information needed to evaluate the assets purchased, commitments extinguished and consideration conveyed in the transaction. See further discussion of PGC at Note 3.

Repurchase of Senior Unsecured Notes. In October 2015, the Company repurchased $100.0 million of its Senior Unsecured Notes comprised of (i) $2.2 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $46.6 million aggregate principal amount of its 7.5% Senior notes due 2021, (iii) $51.2 million aggregate principal amount of its 7.5% Senior Notes due 2023, for approximately $30.0 million cash.

Issuance of Convertible Senior Unsecured Notes. In conjunction with the repurchase of the Senior Unsecured Notes in October 2015, the Company also exchanged $300.0 million of its Senior Unsecured Notes, comprised of (i) $6.6 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $189.3 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $73.5 million aggregate principal amounts of its 8.125% Senior Notes due 2022 and (iv) $30.6 million aggregate principal amount of its 7.5% Senior Notes due 2023, for (i) $269.4 million aggregate principal amount of 8.125% Convertible Senior Notes due 2022 and (ii) $30.6 million aggregate principal amount of 7.5% Convertible Senior Notes due 2023.

Conversions of Long-Term debt to Common Stock. As of November 4, 2015, holders of $97.2 million aggregate principal amount of its 8.125% Convertible Senior Notes due 2022 and $6.9 million aggregate principal amount of its 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 37.9 million shares of Company common stock and aggregate cash payments of $12.9 million for accrued interest and early conversion payments.

Sale of Other Property, Plant and Equipment. During October 2015, the Company signed an agreement to sell one of its properties located in downtown Oklahoma City, Oklahoma. See further discussion at Note 5.

Conversion of 7% Convertible Perpetual Preferred to Common Stock. During October 2015, holders of 216,000 shares of 7% convertible perpetual preferred stock converted such shares into shares of the Company’s common stock at the then-prevailing conversion rate, resulting in the issuance of approximately 2.8 million shares of common stock.

Purchase of Oil and Natural Gas Assets. On November 3, 2015, the Company signed an agreement to acquire 16 producing wells and approximately 136,000 acres in the North Park Basin, Jackson County, Colorado for approximately $190.0 million, pending standard due diligence and post-closing adjustments.

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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 the Company’s 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 the Company’s audited consolidated financial statements and the accompanying notes included in the 2014 Form 10-K. The Company’s discussion and analysis includes the following subjects:


•	Overview;


•	Results by Segment;


•	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 nine-month periods ended September 30, 2015 and 2014, 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

SandRidge Energy, Inc. is an oil and natural gas company with a principal focus on exploration and production activities in the Mid-Continent region of the United States. The Company’s mission is to become a high-return, growth-oriented resource conversion company in the Mid-Continent where it has determined it has competitive advantages, such as an industry leading cost structure, subsurface knowledge, existing infrastructure and broader infrastructure capabilities and size and scale.

The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater gathering and disposal system, an electrical transmission system and a drilling and related oil field services business.

Recent Events

Repurchase, Exchange and Redemption of Senior Unsecured Notes. In August 2015, the Company repurchased approximately $250.0 million of its Senior Unsecured Notes for approximately $94.5 million cash and issued $275.0 million aggregate principal amount of Convertible Senior Unsecured Notes in exchange for $275.0 million aggregate principal amount of its Senior Unsecured Notes. Subsequent to this exchange, holders of the Company’s Convertible Senior Unsecured Notes have redeemed approximately $21.9 million in aggregate principal amount ($6.5 million net of discount and including holders’ conversion feature) of the Convertible Senior Unsecured Notes for approximately 8.0 million shares of the Company’s common stock through September 30, 2015. The repurchase and exchange of the Company’s Senior Unsecured Notes and subsequent redemptions of the Company’s Convertible Senior Unsecured Notes resulted in an aggregate gain on extinguishment of debt of approximately $340.7 million.

During the second quarter of 2015, the Company issued to a holder of its Company’s 7.5% Senior Notes due 2021 and 8.125% Senior Notes due 2022, approximately 28.0 million shares of the Company’s common stock in exchange for an aggregate $50.0 million principal amount of the notes and as payment for the interest accrued thereon since the last interest payment date. The exchange resulted in a gain on extinguishment of debt of $17.9 million.

Senior Secured Notes. On June 10, 2015, the Company completed the issuance and sale of $1.25 billion in aggregate principal amount of Senior Secured Notes, which bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due upon maturity. Net proceeds from the issuance were approximately $1.21 billion, a portion of which was used to repay amounts outstanding at that time under the Company’s senior credit facility.

Senior Credit Facility. On June 10, 2015, concurrent with the issuance and sale of $1.25 billion in aggregate principal amount of its Senior Secured Notes described above, the Company and its lenders amended the credit agreement to, among other

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things, (i) eliminate financial covenants requiring maintenance of certain levels for the ratio of total net debt to EBITDA and the ratio of EBITDA to interest expense, (ii) amend the financial covenant requiring maintenance of the ratio of total secured debt under the senior credit facility to EBITDA to 2.00:1.00 from 2.25:1.00 at quarter end, (iii) increase the permitted incurrence of additional junior debt, which may be secured, to an amount not to exceed $1.75 billion from $500.0 million, and (iv) to lower the borrowing base from $900.0 million to $500.0 million. On August 13, 2015, the credit agreement was amended to allow the Company to redeem or purchase Senior Unsecured Notes for up to $200.0 million in cash subject to certain limitations.

2014 Divestiture. On February 25, 2014, the Company sold subsidiaries that owned the Gulf Properties, for approximately $702.6 million, net of working capital adjustments and post-closing adjustments, and the buyer’s assumption of approximately $366.0 million of related asset retirement obligations. The Company retained a 2.0% overriding royalty interest in certain exploration prospects. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss on the sale. The Company used the proceeds from the sale to fund its drilling in the Mid-Continent during 2014. Additionally, the Company settled a portion of its existing oil derivative contracts in January and February 2014 prior to their respective maturities to reduce volumes hedged in proportion to the anticipated reduction in daily production volumes due to the sale, which resulted in cash payments of approximately $69.6 million.

Production, revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties included in the Company’s results for the nine-month period ended September 30, 2014 were as follows:



	Nine Months Ended September 30, 2014 (1)
Production (MBoe)	1,321
Revenues (in thousands)	$	90,920
Expenses (in thousands)	$	63,674

_______________

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

Operational Activities

Operational activities for the three and nine-month periods ended September 30, 2015 include the following:

•

Total production for the three-month period ended September 30, 2015 was comprised of approximately 30.8% oil, 52.3% natural gas and 16.9% NGLs compared to 36.0% oil, 48.9% natural gas and 15.1% NGLs in the same period of 2014. Total production for the nine-month period ended September 30, 2015 was comprised of approximately 32.6% oil, 50.8% natural gas and 16.6% NGLs compared to 38.1% oil, 49.9% natural gas and 12.0% NGLs in the same period of 2014.


•	Mid-Continent properties contributed approximately 6.5 MMBoe, or 88.4%, and 20.7 MMBoe, or 88.7% of the Company’s total production, for the three and nine-month periods ended September 30, 2015, respectively, compared to approximately 6.3 MMBoe, or 85.8%, and 16.3 MMBoe, or 78.2% for the three and nine-month periods ended September 30, 2014.


•	Reduced the total rigs drilling to four (no rigs drilling disposal wells) at September 30, 2015 from 35 (including four drilling disposal wells) at December 31, 2014, and 37 (including one drilling disposal wells) at September 30, 2014.


•	Drilled 20 and 145 wells, respectively, excluding salt water disposal wells, in the Mid-Continent area during the three and nine-month periods ended September 30, 2015.


•	Discontinued drilling and oil field services operations in the Permian area as a result of declining oil prices and decreased demand for drilling and oilfield services in the region during the first quarter of 2015.

Outlook

In response to the sharp pricing declines experienced in the latter half of 2014 and into 2015, the Company established a 2015 capital expenditures budget of approximately $700.0 million, with approximately $650.0 million designated for exploration and production activities. These amounts reflect a decrease from total 2014 capital expenditures of 56% and a decrease from 2014 exploration and production capital expenditures of 57%. In 2015, the Company is capitalizing on its in place saltwater gathering and disposal and electrical systems by focusing its drilling efforts on locations that can most effectively make use of this existing infrastructure, while also continuing its multilateral program within a high-graded inventory of locations including newly-targeted formations such as the Chester and Woodford formations. To that end, the Company intends to invest only in projects that are expected to have a positive return at recent strip pricing.

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The Company’s estimated proved reserve volumes were 443.5 MMBoe at September 30, 2015 based on internal estimates using the SEC-mandated historical twelve-month unweighted average pricing at such date, which were $55.73 per barrel of oil and $3.06 per Mcf of natural gas. Applying the actual October 1, 2015 benchmark commodities prices to November 1, 2015 and December 1, 2015, the twelve-month unweighted average prices would have been $46.90 per barrel of oil and $2.66 per Mcf of natural gas. If the Company’s third quarter reserves estimates were made using the reduced twelve-month average prices, and without regard to additions or other further revisions to reserves other than as a result of such pricing changes, the Company’s internally estimated proved reserves as of September 30, 2015 would decrease by approximately 12%, primarily as a result of the loss of proved undeveloped locations. While the Company is still finalizing its capital plan for 2016, it currently expects to execute a smaller drilling program than the six rig average in the third quarter of 2015. As plans for 2016 and beyond will necessarily incorporate depressed current and strip commodity prices, the Company’s preliminary work suggests that the 2015 year-end reserve report will reflect meaningful decreases in total proved reserves. The Company’s current assessment of reserves at December 31, 2015 indicates the impact of lower commodity prices could result in a decrease in total proved reserves from those calculated as of December 31, 2014 of 19%, with proved developed producing reserves accounting for approximately 5% and proved undeveloped and proved developed nonproducing reserves accounting for approximately 14%. All reserve estimates provided in this Form 10-Q were determined by Company reservoir engineers and, accordingly, have not been fully assessed by independent petroleum consultants.

In addition to the impact of lower commodities prices, the Company’s proved reserve estimates as of December 31, 2015 and their estimated discounted value and standardized measure will be impacted by changes in lease operating costs, future development costs, production, exploration and development activities.

In light of current commodity prices and the Company’s leverage position, the Company continues to analyze a variety of transactions and mechanisms designed to reduce debt and/or increase net income, including the monetization of non-income producing assets, the retirement or purchase of outstanding debt securities through cash purchases and/or exchanges for equity or other Company securities in open market purchases, privately negotiated transactions or otherwise and opportunistic acquisitions. Such transactions, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

Results by Segment

The Company operates in three reportable business segments: exploration and production, drilling and oil field services and midstream services. These segments represent the Company’s three main business units, each offering different products and services. The exploration and production segment is engaged in the exploration and production of oil and natural gas properties and includes the activities of the Royalty Trusts. The drilling and oil field services segment is engaged in the contract drilling of oil and natural gas wells and provides various oil field services. The midstream services segment is engaged in the purchasing, gathering, treating and marketing of natural gas and coordinates the delivery of electricity for the Company’s exploration and production operations in the Mid-Continent.

Management evaluates the performance of the Company’s business segments based on income (loss) from operations. Results of these measurements provide important information to the Company about the activity, profitability and contributions of each of the Company’s lines of business. The results of the Company’s business segments for the three and nine-month periods ended September 30, 2015 and 2014 are discussed below.

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Exploration and Production Segment

The Company generates the majority of its consolidated revenues and cash flow from the production and sale of oil, natural gas and NGLs. The Company’s revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs and on the Company’s ability to find, economically develop and produce its reserves. The primary factors affecting the financial results of the Company’s exploration and production segment are the prices the Company receives for its oil, natural gas and NGL production, the quantity of oil, natural gas and NGLs it produces and changes in the fair value of its 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 NYMEX prices for oil and natural gas during the three and nine-month periods ended September 30, 2015 and 2014 are shown in the table below:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Oil (per Bbl)	$	46.50	$	97.25	$	51.01	$	99.62
Natural gas (per Mcf)	$	2.75	$	3.95	$	2.79	$	4.41

In order to reduce the Company’s exposure to price fluctuations, the Company enters into commodity derivative contracts for a portion of its anticipated future oil and natural gas production as discussed in “Item 3. Quantitative and Qualitative Disclosures About Market Risk.” Reducing the Company’s exposure to price volatility helps mitigate the risk that it will not have adequate funds available for its capital expenditure programs. However, as commodity prices have been depressed for an extended period, the Company recently has been limited in its ability to significantly mitigate price risk through commodity derivative transactions for future production.

Saltwater Gathering and Disposal System. Included within the Company’s full cost pool is a saltwater gathering and disposal system that included over 1,150 miles of gathering lines and over 200 disposal wells at September 30, 2015. This system assists in the economically efficient production of oil and natural gas by reducing the overall cost of water disposal, which directly reduces production costs. The system has a current injection capacity of over 3.0 million barrels of water per day.

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Set forth in the table below is financial, production and pricing information for the exploration and production segment for the three and nine-month periods ended September 30, 2015 and 2014.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Results (in thousands)
Revenues
Oil	$	98,023		$	250,121		$	361,539		$	769,907
NGL	16,558			39,780			57,055			94,602
Natural gas	50,554			69,712			156,805			240,326
Other	(1		)	—			12			2,048
Inter-segment revenue	—			—			(12		)	(26		)
Total revenues	165,134			359,613			575,399			1,106,857
Operating expenses
Production	73,201			83,211			245,399			258,228
Production taxes	3,652			8,380			12,548			24,027
Depreciation and depletion—oil and natural gas	66,501			112,569			266,906			325,021
Accretion of asset retirement obligations	1,132			1,116			3,323			7,927
Impairment	1,038,757			—			3,611,429			164,779
Gain on derivative contracts	(42,211		)	(132,575		)	(59,034		)	(4,792		)
Gain on sale of assets	—			(11		)	(24		)	(33		)
Other operating expenses	13,005			11,732			49,513			43,203
Total operating expenses	1,154,037			84,422			4,130,060			818,360
(Loss) income from operations	$	(988,903	)	$	275,191		$	(3,554,661	)	$	288,497

Production data
Oil (MBbls)	2,262			2,644			7,604			7,927
NGL (MBbls)	1,246			1,109			3,883			2,500
Natural gas (MMcf)	23,058			21,501			71,133			62,335
Total volumes (MBoe)	7,351			7,337			23,343			20,816
Average daily total volumes (MBoe/d)	79.9			79.7			85.5			76.2
Average prices—as reported(1)
Oil (per Bbl)	$	43.33		$	94.60		$	47.55		$	97.12
NGL (per Bbl)	$	13.29		$	35.84		$	14.69		$	37.84
Natural gas (per Mcf)	$	2.19		$	3.24		$	2.20		$	3.86
Total (per Boe)	$	22.46		$	49.01		$	24.65		$	53.08
Average prices—including impact of derivative contract settlements(2)
Oil (per Bbl)	$	72.18		$	94.86		$	80.42		$	95.85
NGL (per Bbl)	$	13.29		$	35.84		$	14.69		$	37.84
Natural gas (per Mcf)	$	2.28		$	3.37		$	2.61		$	3.64
Total (per Boe)	$	31.61		$	49.48		$	36.58		$	51.95

__________________


(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.

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The table below presents production by area of operation for the three and nine-month periods ended September 30, 2015 and 2014 and illustrates the impact of (i) the Company’s continued development of its Mid-Continent assets, and (ii) the sale of the Gulf Properties in February 2014.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	Production (MBoe)	% of Total		Production (MBoe)	% of Total		Production (MBoe)	% of Total		Production (MBoe)	% of Total
Mid-Continent	6,495	88.4	%	6,292	85.8	%	20,700	88.7	%	16,280	78.2	%
Gulf of Mexico / Gulf Coast	—	—	%	—	—	%	—	—	%	1,321	6.3	%
Permian Basin	389	5.3	%	512	7.0	%	1,215	5.2	%	1,590	7.6	%
Other - west Texas	467	6.3	%	533	7.2	%	1,428	6.1	%	1,625	7.9	%
Total	7,351	100.0	%	7,337	100.0	%	23,343	100.0	%	20,816	100.0	%

Revenues

Exploration and production segment revenues from oil, natural gas and NGL sales decreased $194.5 million, or 54.1%, for the three-month period ended September 30, 2015, from the same period in 2014. Approximately $168.3 million of the total net decrease was due to a decline in the average prices received primarily for oil, and to a lesser extent, natural gas and NGL production. The remaining $26.2 million of the total decrease was due primarily to a decline in oil production largely as a result of the planned reduction in the Company’s 2015 drilling activity.

Exploration and production segment revenues from oil, natural gas and NGL sales decreased $529.4 million, or 47.9%, for the nine-month period ended September 30, 2015, from the same period in 2014. Approximately $584.3 million of the total net decrease was due to a decline in the average prices received primarily for oil, and to a lesser extent, natural gas and NGL production. This decrease was partially offset by an increase of $54.9 million due to a 2,527 MBoe, or 12.1%, increase in combined production, stemming largely from the continued development of the Company’s Mid-Continent properties.

Operating Expenses

Production expense includes costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses decreased $10.0 million, or 12.0% for the three-month period ended September 30, 2015 compared to the same period in 2014, primarily due to a decrease in well activity as a result of fewer new wells being brought on production and a reduction in workover activity in 2015. Production costs per Boe decreased to $9.96 per Boe for the 2015 period from $11.34 per Boe in the 2014 period. Production expenses for the nine-month period ended September 30, 2015 decreased $12.8 million, or 5.0% from the same period in 2014. Production costs per Boe decreased to $10.51 per Boe for the 2015 period from $12.41 per Boe in the 2014 period, primarily as a result of (i) the sale of the Gulf Properties in February 2014, which had higher production costs inherent with offshore operations, and (ii) an increase in total combined production for the nine-month period ended September 30, 2015 period compared to the same period in 2014.

Production taxes decreased by $4.7 million, or 56.4% and $11.5 million, or 47.8%, for the three and nine-month periods ended September 30, 2015, respectively, compared to the same periods in 2014, primarily due to the decrease in oil, natural gas and NGL revenues. Production taxes as a percentage of oil, natural gas and NGL revenue were consistent at approximately 2.2% for the three-month period ended September 30, 2015 compared to 2.3% for the same period in 2014 and 2.2% for both the nine-month periods ended September 30, 2015 and 2014.

Depreciation and depletion for the Company’s oil and natural gas properties decreased by $46.1 million and $58.1 million for the three and nine-month periods ended September 30, 2015, respectively, compared to the same periods in 2014, largely as a result of a decrease in the depreciation and depletion rates per Boe. The average depreciation and depletion rates per Boe were $9.05 and $11.43 for the three and nine-month periods ended September 30, 2015, respectively, compared to $15.34 and $15.61 for the three and nine-month periods ended September 30, 2014, respectively. The decreases in the depreciation and depletion rates are primarily due to (i) the sale of the Gulf Properties in February 2014, (ii) full cost ceiling impairments recorded in the nine-month period ended September 30, 2015 and the three-month period ended March 31, 2014, and (iii) changes in future production and planned capital expenditures that occurred in conjunction with the year end 2014 budgeting and reserves estimation processes. The decreases due to the depreciation and depletion rates were partially offset by increases in production for the 2015 periods compared to the 2014 periods.

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Accretion of asset retirement obligations was comparable for the three-month periods ended September 30, 2015 and 2014 and decreased by $4.6 million for the nine-month period ended September 30, 2015, compared to the same period in 2014, primarily due to the assumption by Fieldwood of asset retirement obligations associated with the Gulf Properties sold in February 2014.

The Company incurred full cost ceiling limitation impairments of $1.0 billion for the three-month period ended September 30, 2015, and $3.6 billion and $164.8 million for the nine-month periods ended September 30, 2015 and 2014, respectively. No full cost ceiling limitation impairment was incurred for the three-month period ended September 30, 2014. The 2015 impairments were due to full cost ceiling limitations at March 31, 2015, June 30, 2015, and September 30, 2015, resulting primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued into 2015. The 2014 impairment was due to a full cost ceiling limitation resulting from the divestiture of the Gulf Properties, as the present value of future net revenues associated with the Gulf Properties exceeded the associated reduction to the full cost pool.

While it is difficult to project future impairment write-downs in light of numerous variables involved, the following analysis illustrates the impact of lower commodities pricing on impairment charges. Applying the reduced twelve-month average prices described above under “Outlook” to the September 30, 2015 ceiling test for impairment, the Company estimates the impairment charge for the quarter would have increased by approximately $625.0 million. Accordingly, at this time, the Company expects to incur a further ceiling test impairment write-down in the fourth quarter of 2015 assuming commodities prices do not increase dramatically.

The Company recorded gains on commodity derivative contracts of $42.2 million and $132.6 million for the three-month periods ended September 30, 2015 and 2014, respectively, which include net cash receipts upon settlement of $67.3 million and $3.4 million, respectively. The Company recorded a gain on commodity derivative contracts of $59.0 million and $4.8 million for the nine-month periods ended September 30, 2015 and 2014, respectively, which includes net cash (receipts) payments upon settlement of $(278.6) million and $92.9 million, respectively. Included in the net cash payments for the nine-month period ended September 30, 2014 are $69.6 million of cash payments related to the early settlements of commodity derivative contracts primarily as a result of the sale of the Gulf Properties in February 2014.

The Company’s 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 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 the Company’s 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 the Company’s commodity derivative contracts.

See “Consolidated Results of Operations” below for a discussion of other operating expenses.

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Drilling and Oil Field Services Segment

The financial results of the Company’s drilling and oil field services segment depend primarily on demand and prices that can be charged for its services. On a consolidated basis, drilling and oil field service revenues earned and expenses incurred in performing services for third parties, including third-party working interests in wells the Company operates, are included in drilling and services revenues and cost of sales. Drilling and oil field service revenues earned and expenses incurred in performing services for the Company’s own account are eliminated in consolidation. The primary factors affecting the results of the Company’s drilling and oil field services segment are the rates received on rigs drilling for third parties, the number of days drilling for third parties and the amount of oil field services provided to third parties.

Set forth in the table below is financial and operational information for the drilling and oil field services segment for the three and nine-month periods ended September 30, 2015 and 2014.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Results (in thousands)
Revenues	$	14,754		$	51,082		$	56,545		$	150,054
Inter-segment revenue	(10,182		)	(29,734		)	(36,887		)	(92,774		)
Total revenues	4,572			21,348			19,658			57,280
Operating expenses	12,475			22,503			39,086			60,752
Impairment	19,820			—			19,820			3,133
Loss from operations	$	(27,723	)	$	(1,155	)	$	(39,248	)	$	(6,605	)

Drilling rig statistics
Average number of operational rigs owned during the period	11.0			27.0			20.2			27.0
Average number of rigs working for third parties	—			5.9			—			5.3
Number of days drilling for third parties	—			530			—			1,453
Average drilling revenue per day per rig drilling for third parties(1)	$	—		$	14,411		$	—		$	14,725

Rig status - September 30							2015			2014
Working for SandRidge							4			12
Working for third parties							—			6
Idle(2)							7			9
Total operational							11			27
Non-operational(3)							—			3
Total rigs							11			30

____________________


(1)	Represents revenues from rigs working for third parties, excluding stand-by revenue, divided by the total number of days such drilling rigs were used by third parties during the period. Excludes revenues for related rental equipment.


(2)	The Company’s rigs are primarily intended to drill for its own account; as such, the number of idle rigs does not significantly impact the consolidated results of operations.


(3)	Non-operational rigs at September 30, 2014 were held for sale.

Drilling and oil field services segment revenues and operating expenses decreased $16.8 million and $10.0 million, respectively, for the three-month period ended September 30, 2015, and decreased $37.6 million and $21.7 million, respectively, for the nine-month period ended September 30, 2015, compared to the same periods in 2014, primarily due to a decrease in revenue from work performed for third parties, as well as a decrease in revenue from third-party working interests for work performed on wells in which the Company also has an interest, during the 2015 periods.

During the three and nine-month periods ended September 30, 2015, the Company recorded an impairment of approximately $19.8 million on certain drilling assets in order to adjust their carrying values to fair value based on the Company’s plans for their future use. During the nine-month period ended September 30, 2014, the Company recorded an impairment of approximately $3.1 million on certain drilling assets identified for sale at that time in order to adjust their carrying values to fair value.

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Midstream Services Segment

Midstream services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business, and revenues from coordinating the delivery of electricity to the Company’s exploration and production operations in the Mid-Continent area. The primary factors affecting the results of the Company’s midstream services segment are the quantity of natural gas the Company gathers, treats and markets and the prices it pays and receives for natural gas as well as the rates charged and volumes delivered by the electrical transmission system.

Gas Marketing. On a consolidated basis, midstream and marketing revenues include natural gas sold to third parties and the fees the Company charges to gather, compress and treat this natural gas. Midstream and marketing operating costs represent payments made to third parties for the proceeds from the sale of natural gas owned by such parties, net of any applicable margin, and actual costs the Company charges to gather, compress and treat the natural gas. In general, natural gas purchased and sold by the Company’s midstream services segment is priced at a published daily or monthly index price. Midstream gas services are primarily undertaken to realize incremental margins on natural gas purchased at the wellhead and to provide value-added services to customers.

Provision of Electricity. The Company owns an electrical transmission system in the Mid-Continent area to provide electricity for use in the Company’s exploration and production operations at a lower cost than electricity provided by on-site generation. On a consolidated basis, revenues and expenses from the electrical transmission system relate to electricity provided to third-party working interest owners in Company-operated wells in the Mid-Continent.

Set forth in the table below is financial and operational information for the midstream services segment for the three and nine-month periods ended September 30, 2015 and 2014.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Results (in thousands)
Operating revenues	$	20,812		$	31,132		$	63,123		$	115,846
Inter-segment revenue	(11,974		)	(19,210		)	(36,915		)	(71,405		)
Total revenues	8,838			11,922			26,208			44,441
Operating expenses	10,928			15,140			35,326			51,414
Loss from operations	$	(2,090	)	$	(3,218	)	$	(9,118	)	$	(6,973	)

Gas Marketed
Volumes (MMcf)	1,619			1,855			5,020			5,557
Average price	$	2.59		$	3.84		$	2.57		$	4.36

Midstream services segment revenues and operating expenses decreased $3.1 million and $4.2 million, respectively, for the three-month period ended September 30, 2015, and segment revenues and expenses decreased $18.2 million and $16.1 million, respectively, for the nine-month period ended September 30, 2015, compared to the same period in 2014. These decreases were primarily due to (i) a change in the fee structure for electrical usage during the second quarter of 2014, (ii) decreases in the average price received for natural gas purchased and marketed in west Texas of $1.25 and $1.79 per Mcf for the three and nine-month periods ended September 30, 2015, respectively, compared to the same periods in 2014, and (iii) a decrease in gas compressor rentals in the 2015 periods compared to the 2014 periods.

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Consolidated Results of Operations

Revenues

The Company’s consolidated revenues for the three and nine-month periods ended September 30, 2015 and 2014 are presented in the table below.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
	(In thousands)
Revenues
Oil, natural gas and NGL	$	165,135	$	359,613	$	575,399	$	1,104,835
Drilling and services	4,572		21,348		19,658		57,280
Midstream and marketing	8,838		11,922		26,208		44,706
Other	1,607		1,224		3,802		5,056
Total revenues(1)	$	180,152	$	394,107	$	625,067	$	1,211,877

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(1)

Includes $13.5 million and $37.1 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended September 30, 2015 and 2014, respectively. Includes $46.4 million and $123.2 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the nine-month periods ended September 30, 2015 and 2014, respectively.

The Company’s primary sources of revenue are discussed in “Results by Segment.” See discussion of oil, natural gas and NGL revenues under “Results by Segment—Exploration and Production Segment,” discussion of drilling and services revenues under “Results by Segment—Drilling and Oil Field Services Segment” and discussion of midstream and marketing revenues under “Results by Segment—Midstream Services Segment.”

Other revenues decreased for the nine-month period ended September 30, 2015 compared to the same period in 2014 due primarily to the absence in the 2015 period of revenues generated by the Bullwinkle and other offshore platforms, which were included in the sale of the Gulf Properties in February 2014.

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Expenses

The Company’s consolidated expenses for the three and nine-month periods ended September 30, 2015 and 2014 are presented below.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Expenses
Production	$	72,884		$	82,664		$	244,158		$	256,473
Production taxes	3,652			8,380			12,548			24,027
Cost of sales	4,323			15,992			22,034			38,942
Midstream and marketing	6,633			11,405			22,464			40,659
Depreciation and depletion—oil and natural gas	66,501			112,569			266,906			325,021
Depreciation and amortization—other	11,379			14,417			37,234			45,350
Accretion of asset retirement obligations	1,132			1,116			3,323			7,927
Impairment	1,074,588			54			3,647,845			167,966
General and administrative	34,233			24,589			108,764			95,042
Gain on derivative contracts	(42,211		)	(132,575		)	(59,034		)	(4,792		)
Loss (gain) on sale of assets	6,771			(995		)	2,097			(978		)
Total expenses(1)	$	1,239,885		$	137,616		$	4,308,339		$	995,637

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(1)

Includes $169.4 million and $(3.3) million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended September 30, 2015 and 2014, respectively. Includes $539.2 million and $72.8 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the nine-month periods ended September 30, 2015 and 2014, respectively. Expenses attributable to noncontrolling interests in consolidated VIEs include $166.8 million of allocated full cost ceiling impairment for the three-month period ended September 30, 2015, and $520.2 million and $29.9 million of allocated full cost ceiling impairments for the nine-month periods ended September 30, 2015 and 2014, respectively. There was no such impairment during the three-month period ended September 30, 2014.

See discussion of production expenses, production taxes, depreciation and depletion—oil and natural gas, accretion of asset retirement obligations, impairment, and gain on derivative contracts under “Results by Segment—Exploration and Production Segment,” discussion of cost of sales and impairment under “Results by Segment— Drilling and Oil Field Services Segment” and discussion of midstream and marketing expenses under “Results by Segment—Midstream Services Segment.”

In addition to impairments of the Company’s full cost pool and drilling assets, the Company recorded a $15.4 million impairment on property located in downtown Oklahoma City, Oklahoma during the three and nine-month periods ended September 30, 2015. The impairment was made to adjust the carrying value of the property to the price for which the Company agreed to sell the property in October 2015.

General and administrative expenses increased $9.6 million, or 39.2% for the three-month period ended September 30, 2015 from the same period in 2014 due primarily to (i) recording a legal settlement of $5.1 million in the third quarter of 2015, (ii) an increase of $3.4 million in professional services costs, including legal and consulting fees, and (iii) a $1.3 million increase in severance costs associated with the departure of an executive officer. General and administrative expenses increased $13.7 million, or 14.4%, for the nine-month period ended September 30, 2015 from the same period in 2014 due primarily to the legal settlement noted above, as well as an increase of $7.2 million in professional services costs, including legal and consulting fees.

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

The Company’s other (expense) income, taxes and net (loss) income attributable to noncontrolling interest for the three and nine-month periods ended September 30, 2015 and 2014 are presented in the table below.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Other (expense) income
Interest expense	$	(77,000	)	$	(59,783	)	$	(213,569	)	$	(183,689	)
Gain on extinguishment of debt	340,699			—			358,633			—
Other (expense) income, net	(426		)	(273		)	1,208			3,159
Total other income (expense)	263,273			(60,056		)	146,272			(180,530		)
(Loss) income before income taxes	(796,460		)	196,435			(3,537,000		)	35,710
Income tax expense (benefit)	25			(1,064		)	90			(2,131		)
Net (loss) income	(796,485		)	197,499			(3,537,090		)	37,841
Less: net (loss) income attributable to noncontrolling interest	(156,073		)	40,161			(493,243		)	49,733
Net (loss) income attributable to SandRidge Energy, Inc.	$	(640,412	)	$	157,338		$	(3,043,847	)	$	(11,892	)

Interest expense for the three and nine-month periods ended September 30, 2015 and 2014 consisted of the following:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Interest expense
Interest expense on debt	$	86,313		$	63,606		$	220,600		$	190,928
Amortization of debt issuance costs, discounts and premium	4,457			2,477			9,377			7,439
Write off of debt issuance costs	—			—			7,108			—
Gain on long-term debt holder conversion feature	(10,146		)	—			(10,146		)	—
Capitalized interest	(3,123		)	(6,190		)	(12,741		)	(14,132		)
Total	77,501			59,893			214,198			184,235
Less: interest income	(501		)	(110		)	(629		)	(546		)
Total interest expense	$	77,000		$	59,783		$	213,569		$	183,689

Total interest expense increased $17.2 million and $29.9 million for the three and nine-month periods ended September 30, 2015 compared to the same periods in 2014, primarily due to interest expense associated with the $1.25 billion in Senior Secured Notes issued in June 2015. This increase was partially offset by a gain recognized due to a decrease in the fair value of the convertible notes derivative liability at September 30, 2015.

The Company recognized a gain on extinguishment of debt of $340.7 million and $358.6 million for the three and nine-month periods ended September 30, 2015 primarily in connection with (i) the repurchase and exchange of the Company’s Senior Unsecured Notes in the third quarter of 2015, and (ii) the exchange of certain of the Company’s Senior Unsecured notes, including outstanding accrued interested thereon since the last payment date, for shares of the Company’s common stock during the second quarter of 2015.

See “Note 7 - Long-Term Debt” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of the Company’s long-term debt transactions in 2015.

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The Company’s tax expense and effective tax rate for the three and nine-month periods ended September 30, 2015 continue to be low as a result of the valuation allowance against its net deferred tax asset. The Company’s income tax benefit of $2.1 million for the nine-month period ended September 30, 2014 is primarily related to a reduction in the Company’s liability for unrecognized tax benefits following a favorable outcome pertaining to the Company’s state audits in the amount of $1.3 million and a reduction in federal alternative minimum tax (“AMT”) associated with the tax year ended December 31, 2013 in the amount of $1.2 million. With respect to the AMT, the Company reduced each of the current liability and corresponding deferred tax asset upon finalizing and filing the Company’s federal income tax return for the year ended December 31, 2013. As a result of reducing the deferred tax asset, the Company decreased its valuation allowance against its net deferred tax asset by $1.2 million.

Net (loss) income attributable to noncontrolling interest represents the portion of net loss (income) attributable to third-party ownership in the Company’s consolidated VIEs and subsidiaries. The loss attributable to noncontrolling interest for the three-month period ended September 30, 2015, includes a full cost ceiling impairment attributable to noncontrolling interest of $166.8 million. There was no such impairment during the comparable period of 2014. The loss attributable to noncontrolling interest for the nine-month period ended September 30, 2015 includes a full cost ceiling impairment attributable to noncontrolling interest of $520.2 million compared to a full cost ceiling impairment attributable to noncontrolling interest of $29.9 million for the nine-month period ended September 30, 2014. Additionally, revenues for the Royalty Trusts decreased in the 2015 periods compared to the 2014 periods largely as a result of a decrease in average prices received for production as well as natural declines in production attributable to the Royalty Trusts’ royalty interests. The Company fulfilled its drilling obligations to the Mississippian Trust I in the second quarter of 2013, to the Permian Trust in the fourth quarter of 2014 and to the Mississippian Trust II in the first quarter of 2015. No further wells will be drilled for the Royalty Trusts.

Liquidity and Capital Resources

The Company plans to incur approximately $100.0 million in capital expenditures in the fourth quarter of 2015 and is currently finalizing its capital expenditures budget for 2016. The Company expects to fund its near term capital and debt service requirements and working capital needs with cash on hand ($790.1 million at September 30, 2015), cash flows from operations and, to the extent available, borrowing capacity under its senior credit facility. The senior credit facility has a borrowing base of $500.0 million, which was undrawn at both September 30, 2015 and October 30, 2015. The Company had $11.0 million in outstanding letters of credit secured by the senior credit facility on both September 30, 2015 and October 30, 2015, respectively, which reduced availability under the senior credit facility on a dollar-for-dollar basis. The Company has no maturities of long-term debt prior to 2020, provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019. The Company may choose to issue new long-term debt, subject to market availability, as an alternative to borrowing under its senior credit facility. Alternatively, the Company may issue equity or other convertible debt or non-debt securities in the capital markets, depending on market conditions, to address its funding requirements. In the longer term, the Company expects a portion of its funding needs to be covered by cash flows from operations, and may issue long-term debt or equity or monetize assets to cover any difference between cash flow from operations and capital needs. The Company’s capital expenditures could be further curtailed if the Company’s cash flows decline from expected levels. Because production from existing oil and natural gas wells declines over time, further reductions of capital expenditures used to drill and complete new oil and natural gas wells would likely result in lower levels of oil and natural gas production in the future.

The Company’s primary sources of liquidity and capital resources are proceeds from the issuance of debt securities, cash flows from operating activities, borrowings under the senior credit facility, proceeds from monetizations of assets and the issuance of equity securities. Declines in oil and natural gas prices during the latter portion of 2014 and sustained low prices in 2015 have had a negative effect on the Company’s cash flows from operations. Continued low oil and natural gas prices, or further declines in such prices, could also adversely affect the Company’s ability to incur additional indebtedness under its senior credit facility or access the capital markets on favorable terms, or at all.

The Company’s primary uses of capital are expenditures related to its oil and natural gas properties, such as costs related to the drilling and completion of wells, the acquisition of oil and natural gas properties and other fixed assets, interest payments on its outstanding indebtedness, the payment of dividends on its outstanding convertible perpetual preferred stock if, and when, the Company elects to pay such dividends in cash, and, from time to time, the repayment of long-term debt.

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. For example, prices for West Texas Intermediate light sweet crude oil (“WTI”), have declined from a monthly average of over $105.00 per Bbl in June 2014 to as low as $43.20 per Bbl as recently as October 2015. Henry

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Hub natural gas prices declined from a monthly average of over $6.00 per MMBtu in February 2014 to as low as $2.03 per MMBtu in October 2015. While the Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows, this extended period of depressed commodity prices has limited the Company’s ability to add meaningful volumes to its hedge position.

If the current depressed oil or natural gas prices persist for a prolonged period or further decline, they would have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced, likely resulting in further full cost pool ceiling impairments. In addition, continued low oil and natural gas prices or further declines in such prices could result in a reduction in the size of the borrowing base under the senior credit facility or an inability to borrow thereunder, which would further limit capital expenditures.

In light of current commodity prices and the Company’s leverage position, the Company continues to analyze a variety of transactions and mechanisms designed to enhance financial flexibility and liquidity, including the monetization of assets, the retirement or purchase of its outstanding debt securities through cash purchases and/or exchanges for equity or other Company securities in open market purchases, privately negotiated transactions or otherwise and opportunistic acquisitions. In this regard, the Company has executed the following transactions during the nine-month period ended September 30, 2015:


•	In the second quarter of 2015, the Company issued to a holder of the Company’s 7.5% Senior Notes due 2021 and 8.125% Senior Notes due 2022, approximately 28.0 million shares of the Company’s common stock in exchange for an aggregate $50.0 million principal amount of the notes and as payment for the interest accrued thereon since the last interest payment date.


•	In June 2015, the Company issued $1.25 billion of 8.75% Senior Secured Notes due 2020.


•	In August 2015, the Company repurchased approximately $250.0 million of its Senior Unsecured Notes for approximately $94.5 million cash and issued approximately $275.0 million aggregate principal amount of Convertible Senior Unsecured Notes in exchange for approximately $275.0 million aggregate principal amount of its Senior Unsecured Notes.

Subsequent to September 30, 2015, the Company repurchased approximately $100.0 million of its Senior Unsecured Notes for approximately $30.0 million cash and issued approximately $300.0 million aggregate principal amount of Convertible Senior Unsecured Notes in exchange for approximately $300.0 million aggregate principal amount of its Senior Unsecured Notes.

During the third quarter of 2015, holders of the Company’s Convertible Senior Unsecured Notes converted an aggregate $21.9 million principal amount ($6.5 million net of discount and including derivative) of the Convertible Senior Unsecured Notes resulting in the issuance of approximately 8.0 million shares of the Company’s common stock and aggregate cash payments of $2.7 million consisting primarily of the interest accrued since the last interest payment date and the early conversion payment described in “Indebtedness - Convertible Senior Unsecured Notes” below. Between September 30, 2015 and November 4, 2015, holders of the Company’s Convertible Senior Unsecured Notes converted an aggregate $104.1million principal amount of the Convertible Senior Unsecured Notes resulting in the issuance of approximately 37.9 million shares of the Company’s common stock and aggregate cash payments of $12.9 million consisting primarily of the interest accrued since the last interest payment date and the early conversion payment described below.

The execution of additional such transactions, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

As of September 30, 2015, the Company’s cash and cash equivalents were $790.1 million, including $7.7 million attributable to the Company’s consolidated VIEs which is available to satisfy only obligations of the VIEs. The Company had approximately $3.9 billion in total debt outstanding and $11.0 million in outstanding letters of credit with no amount outstanding under its senior credit facility at September 30, 2015. As of and during the three and nine-month periods ended September 30, 2015, the Company was in compliance with applicable covenants under its senior credit facility and outstanding senior notes. As of October 30, 2015, the Company’s cash and cash equivalents were approximately $707.4 million, including $7.1 million attributable to the Company’s consolidated VIEs. Additionally, there was no amount outstanding under the Company’s senior credit facility and $11.0 million in outstanding letters of credit.

The Company is party to an agreement with Repsol under which the Company will be obligated to carry a portion of Repsol’s drilling and completion costs for wells drilled in the future in the related area of mutual interest. See “Note 5 - Property, Plant and Equipment” for further discussion. In addition, production targets contained in certain gathering and treating arrangements in effect at September 30, 2015 require the Company to incur capital expenditures or make associated shortfall payments.

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Working Capital

The Company’s working capital balance fluctuates as a result of changes in the fair value of its outstanding commodity derivative instruments and due to fluctuations in the timing and amount of its collection of receivables and payment of expenditures related to its exploration and production operations.

At September 30, 2015, the Company had a working capital surplus of $612.5 million compared to a surplus of $47.5 million at December 31, 2014. Current assets increased by $277.1 million and current liabilities decreased by $287.9 million at September 30, 2015, compared to December 31, 2014. The increase in current assets is primarily due to an $608.9 million increase in cash and cash equivalents, which resulted largely from the receipt of $1.21 billion in net proceeds from the issuance of the Senior Secured Notes in June 2015. The increase in cash was partially offset by a decrease of $188.1 million in the net asset position of the Company’s current derivative contracts and a decrease of $131.9 million in accounts receivable, largely resulting from fluctuations in the timing and amount of collections of receivables. The change in current liabilities is primarily due to a decrease of $238.3 million in accounts payable and accrued expenses largely due to (i) a reduction in accrued capital expenditures resulting from a decrease in the number of drilling rigs operating on the Company’s properties, (ii) a decrease in revenue payable to third party owners in Company operated wells due primarily to a decrease in average prices received for oil, gas and NGLs, and (iii) other changes due primarily to fluctuations in the timing and amount of the payment of expenditures related to exploration and production operations during the nine-month period ended September 30, 2015. Additionally, the Company’s current deferred tax liability decreased by $44.7 million primarily as a result of full cost pool impairments recorded in the three and nine-month periods ended September 30, 2015.

Cash Flows

The Company’s cash flows for the nine-month periods ended September 30, 2015 and 2014 are presented in the following table and discussed below:



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash flows provided by operating activities	$	360,886		$	395,684
Cash flows used in investing activities	(729,749		)	(374,091		)
Cash flows provided by (used in) financing activities	977,752			(246,010		)
Net increase (decrease) in cash and cash equivalents	$	608,889		$	(224,417	)

Cash Flows from Operating Activities

The Company’s operating cash flow is primarily influenced by the prices the Company receives for its oil, natural gas and NGLs, the quantity of oil, natural gas and NGLs it sells, settlements of commodity derivative contracts, and third-party demand for its drilling rigs and oil field services and the rates it is able to charge for these services. The Company’s cash flows from operating activities are also impacted by changes in working capital. The decrease in net cash flows provided by operating activities for the nine-month period ended September 30, 2015 compared to the same period in 2014, is primarily due to a reduction in revenues from oil, natural gas and NGLs, largely resulting from of a decrease in average prices received for the Company’s production. The decrease in revenues was partially offset by gains received on settlement of commodity derivative contracts and, to a lesser extent, a reduction in operating expenses during the nine-month period ended September 30, 2015.

Cash Flows from Investing Activities

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

During the nine-month period ended September 30, 2015, cash flows used in investing activities primarily consisted of capital expenditures, excluding acquisitions. During the nine-month period ended September 30, 2014, cash flows used in investing activities resulted from capital expenditures, excluding acquisitions, of approximately $1.1 billion, which were partially offset by proceeds from the sale of assets of approximately $714.3 million primarily from the sale of the Gulf Properties.

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Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the nine-month periods ended September 30, 2015 and 2014 are summarized below:



	Nine Months Ended September 30,
	2015		2014
	(In thousands)
Capital Expenditures
Exploration and production	$	559,515	$	1,056,568
Drilling and oil field services	2,732		10,877
Midstream services	20,400		25,810
Other	18,405		27,282
Capital expenditures, excluding acquisitions	601,052		1,120,537
Acquisitions	3,231		16,920
Total	$	604,283	$	1,137,457

Capital expenditures, excluding acquisitions, decreased by $519.5 million for the nine-month period ended September 30, 2015 from the same period in 2014, primarily due to a decrease in drilling and leasehold expenditures in the Mid-Continent area. The number of drilling rigs operating on the Company’s properties decreased to four rigs at September 30, 2015 from 35 rigs at December 31, 2014. The Company has established a capital expenditures budget of $700.0 million for 2015.

Cash Flows from Financing Activities

The Company’s financing activities provided $1.0 billion of cash for the nine-month period ended September 30, 2015 compared to $246.0 million used in the same period in 2014. The change of $1.2 billion is due primarily to (i) the issuance of $1.25 billion in Senior Secured Notes in June 2015, which was partially offset by cash paid for the repurchase of debt of $94.5 million, and debt issuance costs incurred of $48.0 million, (ii) a decrease of $35.1 million in noncontrolling interest distributions, and (iii) a decrease of $33.8 million in preferred dividends paid in cash during the 2015 period compared to the 2014 period. The decrease in cash dividends paid was primarily due to payment of the semi-annual 7.0% preferred share dividend in May 2015 and the semi-annual 8.5% preferred share dividend in August 2015 in shares of the Company’s common stock, and conversion of the 6% preferred shares to common shares in December 2014. Additionally, during the nine-month period ended September 30, 2014, the Company paid $44.1 million for the early settlement of financing derivatives as a result of the sale of the Gulf Properties and paid $17.5 million to repurchase shares of the Company’s common stock. These payments were partially offset by proceeds from the sale of Royalty Trust units of $22.1 million.

Indebtedness

Long-term debt consists of the following at September 30, 2015 (in thousands):



Senior credit facility	$	—
8.75% Senior Secured Notes due 2020	1,250,000
Senior Unsecured Notes
8.75% Senior Notes due 2020, net of $3,649 discount	401,149
7.5% Senior Notes due 2021, including premium of $2,652	996,309
8.125% Senior Notes due 2022	601,187
7.5% Senior Notes due 2023, net of $2,436 discount	622,923
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $3,113, net of $105,691 discount	36,406
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities $2,361, net of $87,412 discount	29,020
Total debt	$	3,936,994

The indentures governing the senior notes contain covenants imposing certain restrictions on the Company’s activities, including, but not limited to, limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and during the three and nine-month periods

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ended September 30, 2015, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding senior notes.

Maturities of Long-Term Debt. As of September 30, 2015, there are no contractual maturities of long-term debt until January 2020; however, the Senior Secured Notes will mature on June 1, 2020, provided that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019.

Senior Credit Facility. The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. The Company’s borrowing base is generally redetermined in April and October of each year. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, a decrease in such value, whether due to declining commodity prices or a reduction in the Company’s development of reserves would likely cause a reduction in the borrowing base. On June 10, 2015, in connection with an amendment to the senior credit agreement, as discussed further below, the borrowing base was reduced to $500.0 million from $900.0 million, which resulted in the write off of approximately $4.9 million of capitalized debt issuance costs. The borrowing base remained unchanged as a result of the October 2015 redetermination. The next scheduled redetermination is expected to take place in April 2016. Quarterly, the Company pays a commitment fee assessed at an annual rate of 0.5% on any available portion of the senior credit facility.

At September 30, 2015, the Company had no amount outstanding under the senior credit facility and $11.0 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $489.0 million. As of and during the three and nine-month periods ended September 30, 2015, the Company was in compliance with all applicable financial covenants under the senior credit facility.

On June 10, 2015, concurrent with the issuance and sale of $1.25 billion in aggregate principal amount of its Senior Secured Notes, discussed below, the Company and its lenders amended the credit agreement to, among other things, (i) eliminate financial covenants requiring maintenance of certain levels for the ratio of total net debt to EBITDA and the ratio of EBITDA to interest expense, (ii) amend the financial covenant requiring maintenance of the ratio of total secured debt under the senior credit facility to EBITDA to 2.00:1.00 from 2.25:1.00 at quarter end and (iii) increase the permitted incurrence of additional junior debt, which may be secured, to an amount not to exceed $1.75 billion from $500.0 million. On August 13, 2015, the senior credit facility was amended to allow the Company to redeem or purchase Senior Unsecured Notes for up to $200.0 million in cash subject to certain limitations. Concurrent with the October borrowing base redetermination discussed above, on October 16, 2015, the senior credit facility was further amended to increase the amount of Senior Unsecured Notes the Company may redeem or purchase for cash to $275.0 million from $200.0 million.

The amended senior credit facility is available to be drawn on subject to limitations based on its terms, including the Company’s ability to make representations and warranties contained therein regarding the value of the Company’s assets versus its liabilities, and compliance with certain financial covenants, including maintenance of agreed upon levels for the (i) ratio of total secured debt under the senior credit facility to EBITDA described above and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. For the purpose of the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s commodity derivative contracts are disregarded. The senior credit facility matures on the earlier of March 2, 2020 and 91 days prior to the earliest date of any maturity under or mandatory offer to repurchase the Company’s currently outstanding notes.

Additionally, the amended senior credit agreement permits the Company and certain of its subsidiaries to incur additional indebtedness in an aggregate principal amount not to exceed $1.75 billion, which may be secured solely by collateral securing the senior credit facility on a junior lien basis. Any junior lien debt shall be subject to the terms and conditions set forth in an intercreditor agreement, the terms of which are subject to the approval of the lenders, and shall mature no earlier than January 21, 2020. The borrowing base under the senior credit facility will be reduced by $0.25 for every $1.00 of junior debt incurred in excess of $1.5 billion. At September 30, 2015, the Company had incurred $1.25 billion in junior lien debt as a result of the issuance of the Senior Secured Notes in June 2015 and entered into an intercreditor agreement in connection therewith.

Senior Secured Notes. On June 10, 2015, the Company completed the issuance and sale of $1.25 billion in aggregate principal amount of its Senior Secured Notes, which bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due upon maturity. The Senior Secured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on a second-priority secured basis by certain of the Company’s wholly owned subsidiaries. Pursuant to the indenture, the Senior Secured Notes will mature on June 1,

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2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019.

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

Senior Unsecured Notes. The Company’s Senior Unsecured Notes bear interest at a fixed rate per annum, payable semi-annually, with the principal due upon maturity. Certain of the Senior Unsecured Notes were issued at a discount or a premium. The discount or premium is amortized to interest expense over the term of the respective series of Senior Unsecured Notes. The Senior Unsecured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. The Senior Unsecured Notes have a variety of maturities, the first of which is in 2020 and the latest of which is in 2023.

Convertible Senior Unsecured Notes. The Company’s 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 are guaranteed by the same guarantors that guarantee the Senior Unsecured Notes and are subject to covenants and bear payment terms substantially identical to those of the corresponding series of Senior Unsecured Notes of similar tenor, other than the conversion features, described further below, and the extension of the final maturity by one day. The Convertible Senior Unsecured Notes were issued at a discount that is being amortized to interest expense over the term of the respective series of Convertible Senior Unsecured Notes.

The Convertible Senior Unsecured Notes are convertible into shares of Company common stock at the option of holders or, subject to compliance with certain conditions, the Company. In addition, if a holder exercises its right to convert on or prior to the first anniversary of the issuance of the Convertible Senior Unsecured Notes, such holder will receive an early conversion payment in an amount equal to the amount of 18 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. If a holder exercises its right to convert after the first anniversary of the issuance of the Convertible Senior Unsecured Notes but on or prior to the second anniversary of the issuance of such Convertible Senior Unsecured Notes, such holder will receive an early conversion payment in an amount equal to 12 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. No early conversion payment will be made upon a mandatory conversion.

For more information about the senior credit facility, the Senior Secured Notes, the Senior Unsecured Notes, and the Convertible Senior Unsecured Notes, see “Note 7 - Long-Term Debt” to the unaudited condensed consolidated financial statements included in this Quarterly Report.

Contractual Obligations and Off-Balance Sheet Arrangements

At December 31, 2014, the Company’s contractual obligations included long-term debt obligations, a gas gathering agreement, transportation and throughput agreements, third-party drilling rig agreements, asset retirement obligations, operating leases and other individually insignificant obligations. From time to time, the Company enters into transactions that give rise to significant contractual obligations or otherwise result in significant changes to existing contractual obligations. Transactions that occurred during the nine-month period ended September 30, 2015 resulted in the following significant changes to the Company’s contractual obligations from those presented in the 2014 Form 10-K:

•

Long-Term Debt Obligations. The Company’s long-term debt obligation increased by approximately $0.7 billion at September 30, 2015 compared to December 31, 2014, primarily as a result of the issuance of $1.25 billion in Senior Secured Notes in June 2015, which was partially offset by (i) the repurchase of approximately $250.0 million of the Company’s Senior Unsecured Notes for approximately $94.5 million cash in August 2015, (ii) the exchange of an aggregate $50.0 million principal amount of Senior Unsecured Notes ($29.0 million of 7.5% Senior Notes due 2021 and $21.0 million of 8.125% Senior Notes due 2022) for shares of the Company’s stock during the three-month period ended June 30, 2015, and (iii) conversion of an aggregate $21.9 million principal amount ($6.5 million net of discount and including holders’ conversion feature) of the Convertible Senior Unsecured Notes into shares of the Company’s common stock in August and September 2015.


•	Drilling Carry Commitment. As of September 30, 2015, the Company had drilled 453 net wells under a drilling carry arrangement with Repsol and did not satisfy the total drilling commitment under the arrangement of 484 net wells in the area of mutual interest, within the required time period, which ended May 31, 2015. As a result, the Company will carry

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a portion of Repsol’s drilling and completion costs up to approximately $31.0 million for wells drilled in the future in the related area of mutual interest. The Company incurred approximately $3.6 million in costs toward this obligation during the three and nine-month periods ended September 30, 2015, and will continue to record such costs as they are incurred in future periods. See “Note 5 - Property, Plant and Equipment” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion.

Critical Accounting Policies and Estimates

For a description of the Company’s critical accounting policies and estimates, refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the 2014 Form 10-K. For a discussion of recent accounting pronouncements not yet adopted, see “Note 1 - Basis of Presentation” to the Company’s accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report.

Valuation Allowance

In 2008 and 2009, the Company recorded full cost ceiling impairments totaling $3.5 billion on its oil and natural gas assets, resulting in the Company being in a net deferred tax asset position. Management considered all available evidence and concluded that it was more likely than not that some or all of the deferred tax assets would not be realized and established a valuation allowance against the Company’s net deferred tax asset for the period ended December 31, 2008. This valuation allowance has been maintained since 2008. See “Note 12 - Income Taxes” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for more discussion on maintaining the valuation allowance against the Company’s net deferred tax asset.

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

The Company was in a cumulative negative earnings position until the 36-month period ended December 31, 2012 at which time it reached cumulative positive earnings. However, as a result of the Company closing the sale of the oil and natural gas properties in the Permian Basin area of west Texas on February 26, 2013, the Company reverted back to a cumulative negative earnings position for the 36-month period ended March 31, 2013. The Company remains in a cumulative negative earnings position through the 36-month period ended September 30, 2015. One contributing factor to the cumulative negative earnings position for the 36-month period ending September 30, 2015 is the combined effect of the $1.1 billion, $1.5 billion, and $1.1 billion asset impairments, which relate primarily to full cost ceiling impairments of the Company’s oil and natural gas assets, recorded during the three-month periods ending March 31, 2015, June 30, 2015, and September 30, 2015, respectively. Cumulative negative earnings are not a definitive factor in determining to maintain a valuation allowance as all available evidence should be considered, but it is a significant piece of negative evidence in management’s analysis.

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

In determining whether to maintain the valuation allowance, management concluded that the objectively verifiable negative evidence of cumulative negative earnings for the 36-month period ending September 30, 2015, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, management has not changed its judgment regarding the need for a full valuation allowance against its net deferred tax asset. The valuation allowance against the Company’s net deferred tax asset at December 31, 2014 was $594.5 million. The Company’s net deferred tax asset position and corresponding valuation allowance are expected to significantly increase by December 31, 2015, absent the establishment of any offsetting deferred tax liabilities. These increases are primarily a result of the combined effect of the aforementioned asset impairments recorded during the nine-month period ending September 30, 2015.

Additionally, at December 31, 2014, the Company had valuation allowances totaling $55.1 million against specific deferred tax assets for which management has determined it is more likely than not that such deferred tax assets will not be realized

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for various reasons. The valuation allowance against these specific deferred tax assets would not be impacted by the foregoing discussion.

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

General

This discussion provides information about the financial instruments the Company uses to manage commodity prices, including instruments used to manage commodity prices for production attributable to the Royalty Trusts. All contracts are settled in cash and do not require the actual delivery of a commodity at settlement. Additionally, the Company’s exposure to credit risk and interest rate risk is also discussed.

Commodity Price Risk. The Company’s most significant market risk relates to the prices it receives for its oil, natural gas and NGL production. Due to the historical price volatility of these commodities, the Company periodically has entered into, and expects in the future to enter into, derivative arrangements for the purpose of reducing the variability of oil and natural gas prices the Company receives for its production. From time to time, the Company enters into commodity pricing derivative contracts for a portion of its anticipated oil and natural gas production volumes depending upon management’s view of opportunities under the then-prevailing current market conditions. The Company’s senior credit facility limits its ability to enter into derivative transactions to 85% of expected production volumes from estimated proved reserves.

The Company uses, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At September 30, 2015, the Company’s commodity derivative contracts consisted of fixed price swaps, basis swaps and collars, which are described below:



Fixed price swaps	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.

Basis swaps	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for oil or natural gas from a specified delivery point.

Collars	Two-way collars contain a fixed floor price (put) and a fixed ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, the Company receives the fixed price and pays the market price. If the market price is between the call and the put strike price, no payments are due from either party.
	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

The Company’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month or quarter of the contract period. The Company’s three-way oil collars are settled based upon the arithmetic average of NYMEX oil prices during the calculation period for the relevant contract. The Company’s natural gas fixed price swap transactions are settled based upon the NYMEX prices on the final commodity business day for the relevant contract, and the Company’s natural gas collars are settled based upon the NYMEX prices on the penultimate commodity business day for the relevant contract. The Company’s natural gas basis swap transactions are settled based upon the differential between the NYMEX Henry Hub price and Platts Inside FERC Panhandle Eastern Pipe Line price. Settlement for oil derivative contracts occurs in the succeeding month or quarter and natural gas derivative contracts are settled in the production month or quarter.

At September 30, 2015, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

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Natural Gas Price Swaps

Natural Gas Basis Swaps



	Notional (MMcf)	Weighted Average Fixed Price
October 2015 - December 2015	15,640	$	(0.30	)
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
October 2015 - December 2015	1,564	$78.15	$90.03	$103.65
January 2016 - December 2016	2,556	$83.14	$90.00	$100.85

Natural Gas Collars

Because the Company has not designated any of its derivative contracts as hedges for accounting purposes, changes in fair values of the Company’s derivative contracts are recognized as gains and losses in current period earnings. As a result, the Company’s current period earnings may be significantly affected by changes in the fair value of its 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.

The Company recorded a gain on commodity derivative contracts of $42.2 million and $132.6 million for the three-month periods ended September 30, 2015 and 2014, respectively, which include net cash receipts upon settlement of $67.3 million and $3.4 million, respectively. The Company recorded a gain on commodity derivative contracts of $59.0 million and $4.8 million for the nine-month periods ended September 30, 2015 and 2014, respectively, which includes net cash (receipts) payments upon settlement of $(278.6) million and $92.9 million, respectively. Included in the net cash payments for the nine-month period ended September 30, 2014 are $69.6 million of cash payments related to early settlements of commodity derivative contracts primarily as a result of the sale of the Gulf Properties in February 2014.

See “Note 8 - Derivatives” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding the Company’s commodity derivatives.

Credit Risk. All of the Company’s commodity derivative transactions have been carried out in the over-the-counter market. The use of commodity 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 the Company’s derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its commodity derivative counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its commodity derivative contracts. The Company’s commodity derivative contracts are with multiple counterparties to minimize its exposure to any individual counterparty.

A default by the Company under its senior credit facility constitutes a default under its commodity derivative contracts with counterparties that are lenders under the senior credit facility. The Company does not require collateral or other security from counterparties to support derivative instruments. The Company has master netting agreements with all of its derivative contract counterparties, which allow the Company to net its derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Company’s 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. The Company’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the senior credit facility can be offset against amounts owed, if any, to such counterparty under the Company’s senior credit facility. As of September 30, 2015, the counterparties to the Company’s open commodity derivative contracts consisted of nine financial institutions, four of which are also lenders under the Company’s

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senior credit facility. As a result, the Company is not required to post additional collateral under its commodity derivative contracts. To secure their obligations under the commodity derivative contracts novated by the Company, the Permian Trust and Mississippian Trust II have each given the counterparties to such contracts a lien on their royalty interests. See “Note 3 - Variable Interest Entities” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on the Royalty Trusts’ derivative contracts.

The Company’s ability to fund its capital expenditures budget is partially dependent upon the availability of funds under its senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in the senior credit facility, the Company’s bank group consists of 11 financial institutions with commitments ranging from 1.00% to 14.00% of the borrowing base as of September 30, 2015.

Interest Rate Risk. The Company is exposed to interest rate risk on its long-term fixed rate debt and its variable rate senior credit facility. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes the Company to (i) changes in market interest rates reflected in the fair value of the debt and (ii) the risk that the Company may need to refinance maturing debt with new debt at a higher rate. Variable rate debt, where the interest rate fluctuates, exposes the Company to short-term changes in market interest rates as the Company’s interest obligations on these instruments are periodically redetermined based on prevailing market interest rates, primarily LIBOR and the federal funds rate.

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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 September 30, 2015 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission, and such information is accumulated and communicated to management, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There was no change in the Company’s internal control over financial reporting during the quarter ended September 30, 2015 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 April 5, 2011, Wesley West Minerals, Ltd. and Longfellow Ranch Partners, LP filed suit against the Company and SandRidge Exploration and Production, LLC (collectively, the “SandRidge Entities”) in the 83rd District Court of Pecos County, Texas. The plaintiffs, who have leased mineral rights to the SandRidge Entities in Pecos County, allege that the SandRidge Entities have not properly paid royalties on all volumes of natural gas and CO₂ produced from the acreage leased from the plaintiffs. The plaintiffs also allege that the SandRidge Entities have inappropriately failed to pay royalties on CO₂ produced from the plaintiffs’ acreage that results from the treatment of natural gas at the Century Plant. The plaintiffs seek approximately $45.5 million in actual damages for the period of time between January 2004 and December 2011, punitive damages and a declaration that the SandRidge Entities must pay royalties on CO₂ produced from the plaintiffs’ acreage that results from treatment of natural gas at the Century Plant. The Commissioner of the General Land Office of the State of Texas (“GLO”) is named as an additional defendant in the lawsuit as some of the affected oil and natural gas leases described in the plaintiffs’ allegations cover mineral classified lands in which the GLO is entitled to one-half of the royalties attributable to such leases. The GLO has filed a cross-claim against the SandRidge Entities asserting the same claims as the plaintiffs with respect to the leases covering mineral classified lands and seeking approximately $13.0 million in actual damages, inclusive of penalties and interest. On February 5, 2013, the Company received a favorable summary judgment ruling that effectively removes a majority of the plaintiffs’ and GLO’s claims. On April 29, 2013, the court entered an order allowing for an interlocutory appeal of its summary judgment ruling.

The Company intends to continue to defend the remaining issues in the trial court, as well as future appellate proceedings. At the time of the rulings on summary judgment, the lawsuit was still in the discovery stage and, accordingly, an estimate of reasonably possible losses, if any, associated with the remaining causes of action and those rulings reversed by the Court of Appeals cannot be made until all of the facts, circumstances and legal theories relating to such claims and the SandRidge Entities’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

Between December 2012 and March 2013, seven putative shareholder derivative actions were filed in state and federal court in Oklahoma:


•	Arthur I. Levine v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on December 19, 2012 in the U.S. District Court for the Western District of Oklahoma


•	Deborah Depuy v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Paul Elliot, on Behalf of the Paul Elliot IRA R/O, v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant filed on January 29, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Dale Hefner v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 4, 2013 in the District Court of Oklahoma County, Oklahoma


•	Rocky Romano v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on January 22, 2013 in the District Court of Oklahoma County, Oklahoma


•	Joan Brothers v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on February 15, 2013 in the U.S. District Court for the Western District of Oklahoma


•	Lisa Ezell, Jefferson L. Mangus, and Tyler D. Mangus v. Tom L. Ward, et al., and SandRidge Energy, Inc., Nominal Defendant - filed on March 22, 2013 in the U.S. District Court for the Western District of Oklahoma

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transactions in breach of their fiduciary obligations. The Depuy lawsuit also alleges violations of federal securities laws in connection with the Company allegedly filing and distributing certain misleading proxy statements. The lawsuits seek, among other relief, injunctive relief related to the Company’s corporate governance and unspecified damages.

On May 8, 2013, the court stayed the Romano action pending further order of the court. On October 29, 2014, the court granted plaintiff’s application to dismiss the action without prejudice.

On October 7, 2015, the derivative plaintiffs in the Federal Shareholder Derivative Litigation, the Special Litigation Committee, and the individual defendants in the Federal Shareholder Derivative Litigation (Tom Ward, Jim Brewer, Everett Dobson, William Gilliland, Daniel Jordan, Roy Oliver Jr., and Jeffrey Serota), executed a Stipulation of Settlement, which would result in a partial settlement of the Federal Shareholder Derivative Litigation by settling all claims against the individual defendants, subject to certain terms and conditions, including the approval of the court. Under the terms of the proposed partial settlement, the Company would implement or agree to maintain certain corporate governance reforms, and the insurers for the individual defendants would pay $38 million to an escrow fund, which would be used to pay certain expenses arising from pending securities litigation and, to the extent funds remain after paying such expenses, would be paid to the Company without any further restrictions on the Company’s use of such funds. The proposed partial settlement expressly provides, among other terms, that the settling defendants deny all allegations of wrongdoing and are entering into the settlement solely to avoid the costs, disruption, uncertainty, and risk of further litigation. The proposed partial settlement would not settle any of the derivative plaintiffs’ claims against non-settling parties WCT Resources, L.L.C., 192 Investments, L.L.C., and TLW Land & Cattle, L.P in the Federal Shareholder Derivative Litigation. On October 9, 2015, the court issued an Order granting preliminary approval to the partial settlement and establishing procedures for notice to shareholders and consideration of any shareholder objections to the partial settlement. The court also set a hearing for final approval of the partial settlement on December 18, 2015.

An estimate of reasonably possible losses associated with the Hefner action cannot be made at this time. The Company has not established any reserves relating to this action.

On December 5, 2012, James Glitz and Rodger A. Thornberry, on behalf of themselves and all other similarly situated stockholders, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain current and former executive officers of the Company. On January 4, 2013, Louis Carbone, on behalf of himself and all other similarly situated stockholders, filed a substantially similar putative class action complaint in the same court and against the same defendants. On March 6, 2013, the court consolidated these two actions under the caption “In re SandRidge Energy, Inc. Securities Litigation” (the “Securities Litigation”) and appointed a lead plaintiff and lead counsel. On July 23, 2013, plaintiffs filed a consolidated amended complaint, which asserts a variety of federal securities claims against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class of (a) purchasers of SandRidge common stock during the period from February 24, 2011 to November 8, 2012, (b) purchasers of common units of the Mississippian Trust I in or traceable to its initial public offering on or about April 12, 2011, and (c) purchasers of common units of the Mississippian Trust II in or traceable to its initial public offering on or about April 23, 2012. The claims are based on

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allegations that the Company, certain of its current and former officers and directors, and the Mississippian Trusts, among other defendants, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and natural gas reserves, the Company’s capital expenditures, and certain transactions entered into by companies allegedly affiliated with the Company’s former CEO Tom Ward.

Because the Securities Litigation is in the early stages, an estimate of reasonably possible losses associated with it, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs’ claims and defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to the Securities Litigation. Each of the Mississippian Trusts has requested that the Company indemnify it for any losses it may incur in connection with the Securities Litigation.

On July 15, 2013, James Hart and 15 other named plaintiffs filed an amended complaint in the United States District Court for the District of Kansas in an action undertaken individually and on behalf of others similarly situated against SandRidge Energy, Inc., SandRidge Operating Company, SandRidge Exploration and Production, LLC, SandRidge Midstream, Inc., and Lariat Services, Inc. In their Amended Complaint, plaintiffs allege that the defendants failed to properly calculate overtime pay for the plaintiffs and for other similarly situated current and former employees. The plaintiffs further allege that the defendants required the plaintiffs and other similarly situated current and former employees to engage in work-related activities without pay. The plaintiffs assert claims against the defendants for (i) violations of the Fair Labor Standards Act, (ii) violations of the Kansas Wage Payment Act, (iii) breach of contract, and (iv) fraud, and seek to recover unpaid wages and overtime pay, liquidated damages, statutory penalties, economic damages, compensatory and punitive damages, attorneys’ fees and costs, and both pre- and post-judgment interest.

As previously disclosed, on December 18, 2013 the Company received a subpoena duces tecum from the U.S. Department of Justice in connection with an ongoing investigation of possible violations of antitrust laws in connection with the purchase or lease of land, oil or natural gas rights. The transactions that have been the subject of the inquiry date from 2012 and prior years. On April 7, 2015, the U.S. Department of Justice notified the Company that it is a target of a grand jury investigation in the Western District of Oklahoma concerning violations of federal antitrust law. The Company is continuing to respond to the government’s requests in connection with the investigation. The Company is unable to predict the outcome of the government’s investigation, or any range of loss that could be associated with the resolution of any possible criminal charges or civil claims that may be brought against the Company; however, any governmental action or resolution thereof could be material to the Company. The Company is cooperating with the investigation.

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On October 15, 2015, the Court ordered the plaintiffs in the consolidated Gernandt action to file a consolidated complaint by November 24, 2015.

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ITEM 1A. Risk Factors

Except as set forth below, there have been no material changes to the risk factors previously discussed in Item 1A—Risk Factors in the Company’s 2014 Form 10-K.

The Company has received a notice of failure to comply with the NYSE continued listing standard related to the minimum trading price of its common stock. If the Company is unable to avoid the delisting of its common stock from the NYSE, it could have a substantial effect on the Company’s liquidity and results of operations.

On July 23, 2015, the Company received notification from the NYSE that the price of its common stock had fallen below the NYSE’s continued listing standard, which requires that the average closing price not be less than $1.00 per share over a period of 30 consecutive trading days.

Under NYSE rules, a listed company is generally afforded a six-month period following receipt of the NYSE deficiency notice to regain compliance, after which the NYSE will commence suspension of trading and delisting procedures. Regaining compliance requires, on the last trading day of any calendar month, a company’s common stock price per share and 30 trading-day average closing share price to be at least $1.00. During this six month period, a company’s common stock will continue to be traded on the NYSE, subject to compliance with other continued listing requirements and further subject to the discretion of the NYSE to commence delisting procedures against a company’s common stock for other reasons, such as selling for an abnormally low price. Although the Company intends to consider available alternatives, potentially including a reverse stock split, in order to cure the stock price deficiency and return to compliance with the NYSE continued listing requirement, the Company can provide no assurance that these measures will be successful.

If the Company’s common stock ultimately were to be delisted for any reason, including failure to regain compliance with NYSE’s minimum trading price requirement, it could negatively impact the Company by, among other things, (i) reducing the liquidity and market price of the Company’s common stock; (ii) reducing the number of investors willing to hold or acquire the Company’s common stock, which could further harm the performance of the Company’s common stock and negatively impact the Company’s ability to raise equity financing; (iii) limiting the Company’s ability to use a registration statement to offer and sell freely tradable securities, thereby preventing the Company from accessing the public capital markets; and (iv) impairing the Company’s ability to provide equity incentives to its employees.

Legislation or regulatory initiatives intended to address seismic activity could restrict the Company’s ability to dispose of saltwater produced alongside the Company’s hydrocarbons, which could limit the Company’s ability to produce oil and gas economically and have a material adverse effect on the Company’s business.

The Company disposes of large volumes of saltwater produced alongside oil and natural gas in connection with its drilling and production operations, pursuant to permits issued to the Company by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

There exists a growing concern that the injection of saltwater into belowground disposal wells triggers seismic activity in certain areas, including Oklahoma, Kansas and Texas, where the Company operates. In response to these concerns, regulators in some states are pursuing initiatives designed to impose additional requirements in the permitting of saltwater disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in 2014, the Oklahoma Corporation Commission adopted rules for operators of saltwater disposal wells in certain seismically-active areas, or Areas of Interest, in the Arbuckle formation, requiring operators to monitor and record well pressure and discharge volume on a daily basis and further requiring operators of wells permitted for disposal of 20,000 barrels per day or more of saltwater to conduct mechanical integrity testing. On March 25, 2015, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division, or OGCD, issued a directive, expanding the Areas of Interest for induced seismicity. Under the new directive, operators of 347 disposal wells located within the expanded Areas of Interest of the Arbuckle formation were given until April 18, 2015 to demonstrate that their wells were not disposing into or in communication with the crystalline basement rock. Operators of wells in contact or communication with the basement rock were required to reduce the depth of, or “plug back,” those wells or, alternatively, to reduce disposal volume by 50 percent. On July 17, 2015, the OGCD issued another directive, further expanding the covered area to include an additional 211 disposal wells. Under this second directive, operators were given until August 14, 2015 to prove that they were not injecting below the Arbuckle formation or, as necessary, to plug back those wells in contact or communication with the crystalline basement rock, without the option of reducing disposal volume by 50 percent. Most recently, on August 3, 2015, the OGCD imposed further reductions on oil and natural gas wastewater disposal well volume in a prescribed area of northern Oklahoma County and southern

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Logan County, requiring operators to reduce disposal volumes for affected wells by approximately 38 percent below 2014 reported volumes, within a specified 60-day period.

Moreover, in Texas, in 2014, the Texas Railroad Commission, or TRC, published a new rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If a permittee or a prospective permittee fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

Also, in Kansas, in 2014, the governor of Kansas has established a task force composed of various administrative agencies to study and develop an action plan for addressing seismic activity in the state. The Task Force issued a recommended Seismic Action Plan calling for enhanced seismic monitoring and the development of a seismic response plan, and in November 2014, the governor of Kansas announced a plan to enhance seismic monitoring in the state. On March 19, 2015, the Kansas Corporation Commission issued an Order setting limits on the volumes of saltwater that can be injected into the certain areas of seismic concern within the Arbuckle formation.

The adoption and implementation of any new laws, regulations, or directives that restrict the Company’s ability to dispose of saltwater, by plugging back the depths of disposal wells, reducing the volume of oil and natural gas wastewater disposed in such wells, restricting disposal well locations or otherwise, or by requiring the Company to shut down disposal wells, which could require the Company to shut in a substantial number of its oil and natural gas wells or otherwise have a material adverse effect on the Company’s ability to produce oil and gas economically and, accordingly, could materially and adversely affect the Company’s business, financial condition and results of operations.

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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 September 30, 2015.



Period	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program(2)	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in Millions)
July 1, 2015 — July 31, 2015	198,585	$	0.71	N/A	$	88.7
August 1, 2015 — August 31, 2015	187,413	$	0.52	N/A	$	88.7
September 1, 2015 — September 30, 2015	33,857	$	0.45	N/A	$	88.7
Total	419,855			—

____________________


(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.


(2)	In the third quarter of 2014, the Company’s Board of Directors authorized a share repurchase program. There is no fixed termination date for this repurchase program, which may be suspended or discontinued at any time.

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: November 5, 2015

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EXHIBIT INDEX



		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	1/30/2008
3.2	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010	10-Q	001-33784	3.2	8/9/2010
3.3	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated June 4, 2015	10-Q	001-33784	3.3	8/6/2015
3.4	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	3/9/2009
4.1	Indenture, dated as of August 19, 2015, among SandRidge Energy, Inc., the guarantors named therein and U.S. Bank National Association, as Trustee (including the forms of the 2022 Convertible Notes).	8-K	001-33784	4.1	8/19/2015
4.2	Indenture, dated as of August 19, 2015, among SandRidge Energy, Inc., the guarantors named therein and U.S. Bank National Association, as Trustee (including the forms of the 2023 Convertible Notes).	8-K	001-33784	4.2	8/19/2015
10.1.1	First Amendment to Fourth Amended and Restated Credit Agreement, dated as of August 13, 2015, by and among the Company, as borrower, Royal Bank of Canada, as administrative agent, and the lenders signatory thereto.	8-K	001-33784	10.1	8/14/2015
10.1.2	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among the Company, as borrower, Royal Bank of Canada, as administrative agent, and the lenders signatory thereto.	8-K	001-33784	10.1	10/19/2015
10.3.4	2015 Form of Employment Agreement for Executive Vice Presidents and Senior Vice Presidents of SandRidge Energy, Inc.					*
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					*
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					*