Edgar Filing: SANDRIDGE ENERGY INC

Notional (MBbls)

Weighted Average
Fixed Price

April 2015 - December 2015

SD Q1 10Q 3.31.15

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 March 31, 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 May 1, 2015, was 483,986,672.

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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”).

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SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended March 31, 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 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	48
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	65
ITEM 4.	Controls and Procedures	68

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	69
ITEM 1A.	Risk Factors	72
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	73
ITEM 6.	Exhibits	73

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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)



	March 31, 2015			December 31, 2014
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	11,821		$	181,253
Accounts receivable, net	309,037			330,077
Derivative contracts	209,059			291,414
Prepaid expenses	9,893			7,981
Other current assets	7,299			21,193
Total current assets	547,109			831,918
Oil and natural gas properties, using full cost method of accounting
Proved	12,020,208			11,707,147
Unproved	285,942			290,596
Less: accumulated depreciation, depletion and impairment	(7,548,398		)	(6,359,149		)
	4,757,752			5,638,594
Other property, plant and equipment, net	579,249			576,463
Derivative contracts	42,347			47,003
Other assets	130,748			165,247
Total assets	$	6,057,205		$	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)



	March 31, 2015			December 31, 2014
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	538,151		$	683,392
Derivative contracts	119			—
Deferred tax liability	64,517			95,843
Other current liabilities	4,846			5,216
Total current liabilities	607,633			784,451
Long-term debt	3,370,578			3,195,436
Asset retirement obligations	55,966			54,402
Other long-term obligations	16,111			15,116
Total liabilities	4,050,288			4,049,405
Commitments and contingencies (Note 10)
Equity
SandRidge Energy, Inc. stockholders’ equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at March 31, 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 March 31, 2015 and December 31, 2014; aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value, 800,000 shares authorized; 485,095 issued and 483,772 outstanding at March 31, 2015 and 485,932 issued and 484,819 outstanding at December 31, 2014	479			477
Additional paid-in capital	5,207,888			5,204,024
Additional paid-in capital—stockholder receivable	(2,500		)	(2,500		)
Treasury stock, at cost	(7,278		)	(6,980		)
Accumulated deficit	(4,303,036		)	(3,257,202		)
Total SandRidge Energy, Inc. stockholders’ equity	895,559			1,937,825
Noncontrolling interest	1,111,358			1,271,995
Total equity	2,006,917			3,209,820
Total liabilities and equity	$	6,057,205		$	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 March 31,
	2015			2014
	(Unaudited)
Revenues
Oil, natural gas and NGL	$	195,732		$	405,316
Drilling and services	9,845			17,080
Midstream and marketing	8,764			17,910
Other	967			2,750
Total revenues	215,308			443,056
Expenses
Production	89,498			106,856
Production taxes	4,514			7,807
Cost of sales	12,827			12,481
Midstream and marketing	8,107			16,000
Depreciation and depletion—oil and natural gas	106,107			115,185
Depreciation and amortization—other	13,347			15,522
Accretion of asset retirement obligations	1,080			5,746
Impairment	1,083,866			164,779
General and administrative	36,149			38,538
(Gain) loss on derivative contracts	(49,827		)	42,491
Gain on sale of assets	(1,904		)	(19		)
Total expenses	1,303,764			525,386
Loss from operations	(1,088,456		)	(82,330		)
Other (expense) income
Interest expense	(62,842		)	(62,043		)
Other (expense) income, net	(536		)	2,094
Total other expense	(63,378		)	(59,949		)
Loss before income taxes	(1,151,834		)	(142,279		)
Income tax expense	40			127
Net loss	(1,151,874		)	(142,406		)
Less: net loss attributable to noncontrolling interest	(116,921		)	(6,070		)
Net loss attributable to SandRidge Energy, Inc.	(1,034,953		)	(136,336		)
Preferred stock dividends	10,881			13,881
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(1,045,834	)	$	(150,217	)
Loss per share
Basic	$	(2.19	)	$	(0.31	)
Diluted	$	(2.19	)	$	(0.31	)
Weighted average number of common shares outstanding
Basic	478,165			484,798
Diluted	478,165			484,798

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 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)
Three Months Ended March 31, 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	—	—		—		—		—			—			—			(43,716		)	(43,716		)
Purchase of treasury stock	—	—		—		—		—			(1,218		)	—			—			(1,218		)
Retirement of treasury stock	—	—		—		—		(1,218		)	1,218			—			—			—
Stock distributions, net of purchases - retirement plans	—	—		(210	)	—		244			(298		)	—			—			(54		)
Stock-based compensation	—	—		—		—		4,840			—			—			—			4,840
Cancellation of restricted stock awards, net of issuance	—	—		(837	)	2		(2		)	—			—			—			—
Net loss	—	—		—		—		—			—			(1,034,953		)	(116,921		)	(1,151,874		)
Convertible perpetual preferred stock dividends	—	—		—		—		—			—			(10,881		)	—			(10,881		)
Balance at March 31, 2015	5,650	$	6	483,772		$	479	$	5,205,388		$	(7,278	)	$	(4,303,036	)	$	1,111,358		$	2,006,917

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)



	Three Months Ended March 31,
	2015			2014
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(1,151,874	)	$	(142,406	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	119,454			130,707
Accretion of asset retirement obligations	1,080			5,746
Impairment	1,083,866			164,779
Debt issuance costs amortization	2,225			2,361
Amortization of discount, net of premium, on long-term debt	142			129
Write off of debt issuance costs	2,221			—
(Gain) loss on derivative contracts	(49,827		)	42,491
Cash received (paid) on settlement of derivative contracts	136,957			(39,164		)
Gain on sale of assets	(1,904		)	(19		)
Stock-based compensation	4,024			6,786
Other	90			188
Changes in operating assets and liabilities	(56,359		)	(81,147		)
Net cash provided by operating activities	90,095			90,451
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(377,052		)	(331,016		)
Acquisition of assets	(1,739		)	(2,352		)
Proceeds from sale of assets	2,755			707,366
Net cash (used in) provided by investing activities	(376,036		)	373,998
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	420,000			—
Repayments of borrowings	(245,000		)	—
Debt issuance costs	(1,905		)	—
Proceeds from sale of royalty trust units	—			22,119
Noncontrolling interest distributions	(43,716		)	(53,118		)
Acquisition of ownership interest	—			(2,730		)
Stock-based compensation excess tax benefit	—			2
Purchase of treasury stock	(1,609		)	(4,350		)
Dividends paid — preferred	(11,261		)	(17,263		)
Cash paid on settlement of financing derivative contracts	—			(44,128		)
Net cash provided by (used in) financing activities	116,509			(99,468		)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(169,432		)	364,981
CASH AND CASH EQUIVALENTS, beginning of year	181,253			814,663
CASH AND CASH EQUIVALENTS, end of period	$	11,821		$	1,179,644
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(90,286	)	$	(92,896	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Change in accrued capital expenditures	$	56,861		$	55,242

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 statements 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 the 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 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 by the Company 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, 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.

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; assignments of fair value and allocations of purchase price in connection with business combinations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

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 three-month period ended March 31, 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. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period with an option of using either a full retrospective or a modified approach 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 the 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 these guarantees, or $9.4 million, at the time the transaction closed. As of March 31, 2015 and December 31, 2014, the fair value of the guarantees was approximately $4.8 million and $5.1 million, respectively. See Note 4 for additional discussion of the determination of the guarantees’ fair value. The guarantees do not include a limit on the potential future payments for which the Company could be obligated; however, Fieldwood has agreed to indemnify the Company for any costs it may incur as a result of the guarantees and to use its best efforts to pay any amounts sought from the Company by the Bureau of Ocean Energy Management that may arise prior to the expiration of the guarantees. The Company has not incurred any costs as a result of this guarantee, which, as of February 25, 2015, it was permitted to terminate under the terms of the agreement with Fieldwood. The Company submitted a request for release of the guarantee to the Bureau of Ocean Energy Management on March 31, 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. During the three-month period ended March 31, 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 statements of operations for the three-month period ended March 31, 2014 (in thousands):



	Three Months Ended March 31, 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

(Unaudited)

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 March 31, 2015 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 on July 1, 2014.


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

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



	March 31, 2015		December 31, 2014
Mississippian Trust I	26.9	%	26.9	%
Permian Trust	25.0	%	25.0	%
Mississippian Trust II	37.6	%	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 that may be recovered by each Royalty Trust under its respective lien was proportionately

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reduced 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 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-month periods ended March 31, 2015 and 2014 were as follows (in thousands):



	Three Months Ended March 31,
	2015(1)		2014(2)
Total distributions	$	50,203	$	68,313
Distributions to third-party unitholders	$	43,716	$	53,118

____________________


(1)	Subordination thresholds were not met for the Permian Trust and Mississippian Trust II’s distributions, 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 and Mississippian Trust II’s distributions, 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 April 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 March 31, 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.

Derivative Agreements. The Company has 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

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open oil and natural gas commodity derivative contracts at March 31, 2015 underlying the derivatives agreements. 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
April 2015 - December 2015	761	$	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 March 31, 2015 and December 31, 2014, $1.1 billion 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 March 31, 2015 and December 31, 2014 consisted of the following (in thousands):



	March 31, 2015			December 31, 2014
Cash and cash equivalents(1)	$	10,016		$	9,387
Accounts receivable, net	14,877			17,660
Derivative contracts	—			6,589
Total current assets	24,893			33,636
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion and impairment(3)	(475,119		)	(284,094		)
	850,823			1,041,848
Total assets	$	875,716		$	1,075,484
Accounts payable and accrued expenses	$	727		$	2,852
Total liabilities	$	727		$	2,852

____________________


(1)	Includes $3.0 million held by the trustee at March 31, 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 $222.9 million and $42.3 million at March 31, 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 three-month period ended March 31, 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 three-month period ended March 31, 2014 is reflected in loss attributable to noncontrolling interest owners in the accompanying unaudited condensed consolidated statement of operations. 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 March 31, 2015 and December 31, 2014 included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):



	March 31, 2015		December 31, 2014
Accounts receivable due from PGC	$	1,280	$	1,141
Accounts payable due to PGC	$	4,120	$	4,163

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 March 31, 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

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

Guarantees. As discussed in Note 2, the Company has guaranteed on Fieldwood’s behalf certain plugging and abandonment obligations associated with the Gulf Properties. The fair value of these guarantees is 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 May 31, 2015, or approximately 60 days subsequent to the Company’s submission to the Bureau of Ocean Energy Management of its request for release of the guarantee (3.59% and 3.71% at March 31, 2015 and December 31, 2014, respectively). The discount and probability of default rates are 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 guarantees is the estimate of future payments for plugging and abandonment, which was developed based upon third-party quotes and current actual costs. Significant increases (decreases) in the estimate of these payments could result 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 March 31, 2015 and December 31, 2014 is included in the table below (in thousands).



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

Derivative contracts. The fair value of the Company’s natural gas basis swaps outstanding during the three-month period ended March 31, 2015 was 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 derivative contracts. The significant unobservable input used in the fair value measurement of the Company’s natural gas basis swaps was 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 March 31, 2015 and December 31, 2014 are included in the table below.



Unobservable Input	Range							Weighted Average			Fair Value
	(Price per Mcf)										(In thousands)
March 31, 2015
Natural gas basis differential forward curve	$	(0.21	)	–	$	(0.47	)	$	(0.34	)	$	1,332
December 31, 2014
Natural gas basis differential forward curve	$	(0.03	)	–	$	(0.38	)	$	(0.29	)	$	350

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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):

March 31, 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	$	—	$	249,955	$	1,735	$	(284	)	$	251,406
Investments	11,679		—		—		—			11,679
	$	11,679	$	249,955	$	1,735	$	(284	)	$	263,085
Liabilities
Guarantees	$	—	$	—	$	4,791	$	—		$	4,791
Commodity derivative contracts	—		—		403		(284		)	119
	$	—	$	—	$	5,194	$	(284	)	$	4,910

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
Guarantees	$	—	$	—	$	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.

The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for guarantees during the three-month periods ended March 31, 2015 and 2014 (in thousands):



	Three Months Ended March 31,
Level 3 Fair Value Measurements - Guarantees	2015			2014
Beginning balance	$	5,104		$	—
Issuances(1)	—			9,446
(Gain) loss on guarantees	(313		)	34
Ending balance	$	4,791		$	9,480

____________________


(1)	Represents the fair value of the guarantees 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, for the three-month period ended March 31, 2014.

The fair value of the guarantees is 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 guarantees as of March 31, 2015 and December 31, 2014 is included in other current liabilities in the accompanying unaudited condensed consolidated balance sheets.

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The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for commodity derivative contracts during the three-month period ended March 31, 2015 (in thousands):



Level 3 Fair Value Measurements - Commodity Derivative Contracts	Three Months Ended March 31, 2015
Beginning balance	$	350
Purchases	347
Loss on derivative contracts	635
Ending balance	$	1,332

Losses due to changes in fair value of the Company’s Level 3 commodity derivative contracts have been included in (gain) loss on derivative contracts in the accompanying unaudited condensed consolidated statements of operations. There were no outstanding Level 3 commodity derivative contracts at March 31, 2014.

See Note 8 for further discussion of the Company’s derivative contracts.

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-month periods ended March 31, 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 unsecured senior fixed rate notes (“Senior Notes”) using pricing for the Senior Notes 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 March 31, 2015 and December 31, 2014 were as follows (in thousands):



	March 31, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
8.75% Senior Notes due 2020(1)	$	292,500	$	445,580	$	303,750	$	445,402
7.5% Senior Notes due 2021(2)	$	728,500	$	1,178,372	$	752,000	$	1,178,486
8.125% Senior Notes due 2022	$	460,125	$	750,000	$	472,500	$	750,000
7.5% Senior Notes due 2023(3)	$	503,250	$	821,626	$	519,750	$	821,548

____________________


(1)	Carrying value is net of $4,420 and $4,598 discount at March 31, 2015 and December 31, 2014, respectively.


(2)	Carrying value includes a premium of $3,372 and $3,486 at March 31, 2015 and December 31, 2014, respectively.


(3)	Carrying value is net of $3,374 and $3,452 discount at March 31, 2015 and December 31, 2014, respectively.

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):



	March 31, 2015			December 31, 2014
Oil and natural gas properties
Proved(1)	$	12,020,208		$	11,707,147
Unproved	285,942			290,596
Total oil and natural gas properties	12,306,150			11,997,743
Less accumulated depreciation, depletion and impairment	(7,548,398		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	4,757,752			5,638,594
Land	16,310			16,300
Non-oil and natural gas equipment(2)	602,359			602,392
Buildings and structures(3)	269,336			263,191
Total	888,005			881,883
Less accumulated depreciation and amortization	(308,756		)	(305,420		)
Other property, plant and equipment, net	579,249			576,463
Total property, plant and equipment, net	$	5,337,001		$	6,215,057

____________________


(1)	Includes cumulative capitalized interest of approximately $42.6 million and $38.1 million at March 31, 2015 and December 31, 2014, respectively.


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


(3)	Includes cumulative capitalized interest of approximately $18.1 million and $17.1 million at March 31, 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 $4.8 billion and $3.7 billion at March 31, 2015 and December 31, 2014, respectively. During the three-month periods ended March 31, 2015 and 2014, the Company reduced the net carrying value of its oil and natural gas properties by $1.1 billion and $164.8 million, respectively, as a result of its first quarter full cost ceiling analysis.

Drilling Carry Commitments

During the three-month period ended March 31, 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 $72.3 million for Repsol’s carry during the three-month period ended March 31, 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 their 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. If the Company does not drill the committed number of wells within such time period, it will be required to carry Repsol’s drilling and completion costs for subsequent wells drilled in the area of mutual interest, up to a maximum of $75.0 million in carry costs. As of March 31, 2015, the Company has drilled 427 net wells under this arrangement and currently anticipates, due to changes in its drilling plan, that it will not satisfy the drilling commitment within the required time period. As a result, the Company currently anticipates that it will carry a portion of Repsol’s drilling and completion costs for wells drilled in the future in the area of mutual interest. Other than the above, the Company has no carry or drilling obligations to Repsol.

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6. Other Assets

Other assets consist of the following (in thousands):



	March 31, 2015		December 31, 2014
Debt issuance costs, net of amortization	$	53,904	$	56,445
Deferred tax asset	64,517		95,843
Investments	11,679		11,106
Other	648		1,853
Total other assets	$	130,748	$	165,247

7. Long-Term Debt

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



	March 31, 2015		December 31, 2014
Senior credit facility	$	175,000	$	—
Senior Notes
8.75% Senior Notes due 2020, net of $4,420 and $4,598 discount, respectively	445,580		445,402
7.5% Senior Notes due 2021, including premium of $3,372 and $3,486, respectively	1,178,372		1,178,486
8.125% Senior Notes due 2022	750,000		750,000
7.5% Senior Notes due 2023, net of $3,374 and $3,452 discount, respectively	821,626		821,548
Total debt	3,370,578		3,195,436
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,370,578	$	3,195,436

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. As of March 31, 2015, the senior credit facility contains 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 may not 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 must 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 must be at least 1.00:1.00 at each quarter end. The 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 may 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 matures in October 2019.

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. 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-month period ended March 31, 2015, the Company was in compliance with all applicable financial covenants under the senior credit facility.

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, certain intercompany

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debt of the Company, and substantially all of the Company’s 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 considered by the lenders in determining the borrowing base for the senior credit facility.

At the Company’s election, interest under the senior credit facility, as amended, is determined by reference to (a) the London Interbank Offered Rate (“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 Bank of America 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 end of the applicable interest period 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 annual rates ranging from 0.375% to 0.5% on any available portion of the senior credit facility.

Borrowings under the senior credit facility may not exceed the lower of the committed amount or the borrowing base, which is subject to periodic redeterminations. On February 23, 2015, in connection with the amendment to the senior credit agreement described above, the borrowing base was reduced to $900.0 million from $1.2 billion, which resulted in the write off of approximately $2.2 million of capitalized debt issuance costs. The next scheduled borrowing base redetermination is expected to take place in October 2015. 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.

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 $500.0 million, 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 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.

The Company did not draw on the senior credit facility during 2014. The senior credit facility had $175.0 million drawn at March 31, 2015 and had $11.6 million in outstanding letters of credit secured by the senior credit facility, which reduce the availability under the senior credit facility on a dollar-for-dollar basis. At March 31, 2015, the Company had neither incurred junior debt not entered into any intercreditor agreement.

Senior Notes

The Company’s Senior Notes bear interest at a fixed rate per annum, payable semi-annually, with the principal due upon maturity. Certain of the Senior 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 Notes. The Senior 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 $70.2 million incurred in connection with the offerings and subsequent registered exchange offers, including those discussed below, of the Senior Notes outstanding at March 31, 2015 are included in other assets in the accompanying unaudited condensed consolidated balance sheets and are being amortized to interest expense over the term of the respective series of Senior Notes.

Indentures. Each of the indentures governing the Company’s Senior 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-month period ended March 31, 2015, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Notes.

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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 contract fair values are recognized in earnings. Cash settlements and valuation gains and losses are included in (gain) loss on derivative contracts for commodity derivative contracts in the consolidated statements of operations. Commodity derivative contracts are settled on a monthly or quarterly basis. Derivative assets and liabilities arising from the Company’s derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheets.

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. These derivative contracts 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 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. At March 31, 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 and covered volumes of oil and natural gas production through March 31, 2015 for the Permian Trust. 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.

In accordance with the terms of the respective derivatives agreements, the Company novated certain of the 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 March 31, 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.

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



Type of Contract	Balance Sheet Classification	March 31, 2015			December 31, 2014
Derivative assets
Oil price swaps	Derivative contracts-current	$	145,304		$	204,072
Natural gas price swaps	Derivative contracts-current	7,762			29,648
Natural gas basis swaps	Derivative contracts-current	1,452			350
Oil collars - three way	Derivative contracts-current	53,890			56,289
Natural gas collars	Derivative contracts-current	935			1,055
Oil price swaps	Derivative contracts-noncurrent	32,193			36,288
Natural gas basis swaps	Derivative contracts-noncurrent	283			—
Oil collars - three way	Derivative contracts-noncurrent	9,871			10,715
Derivative liabilities
Natural gas basis swaps	Derivative contracts-current	(403		)	—
Total net derivative contracts		$	251,287		$	338,417

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

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Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its 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 derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of March 31, 2015, the counterparties to the Company’s open derivative contracts consisted of nine financial institutions, all of which are also lenders under the Company’s senior credit facility. The Company is not required to post additional collateral under its derivative contracts as the majority of the counterparties to the Company’s derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the derivative contracts novated by the Company, the Permian Trust and the Mississippian Trust II have each given the counterparties to such contracts a lien on its royalty interests. The following tables summarize (i) the Company's 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 (for SandRidge's derivative contracts) and under liens granted on the royalty interests (for the Permian Trust and the Mississippian Trust II) (in thousands):

March 31, 2015



	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	209,343	$	(284	)	$	209,059	$	—		$	209,059
Derivative contracts - noncurrent	42,347		—			42,347		—			42,347
Total	$	251,690	$	(284	)	$	251,406	$	—		$	251,406
Liabilities
Derivative contracts - current	$	403	$	(284	)	$	119	$	(119	)	$	—
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	403	$	(284	)	$	119	$	(119	)	$	—

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) loss on derivative contracts of $(49.8) million and $42.5 million for the three-month periods ended March 31, 2015 and 2014, respectively, as reflected in the accompanying unaudited condensed consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(137.0) million and $23.4 million, respectively. For the three-month period ended March 31, 2014, $69.6 million of cash payments related to 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 March 31, 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
April 2015 - December 2015	46,750	$	(0.30	)
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
April 2015 - December 2015	3,856	$77.20	$90.18	$103.55
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 March 31, 2015 is as follows (in thousands):



Asset retirement obligations at December 31, 2014	$	54,402
Liability incurred upon acquiring and drilling wells	558
Liability settled or disposed in current period	(74		)
Accretion	1,080
Asset retirement obligations at March 31, 2015	55,966
Less: current portion	—
Asset retirement obligations, net of current	$	55,966

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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 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.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against the Company, SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain current and former directors and senior executive officers of the Company (collectively, the “defendants”) in the U.S. District Court for the District of Connecticut. On October 28, 2011, the plaintiffs filed an amended complaint alleging substantially the same allegations as those contained in the original complaint. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and to the plaintiffs prior to the entry into a participation agreement among Patriot Exploration, LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P's oil and natural gas properties. To date, the plaintiffs have invested approximately $16.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. On November 28, 2011, the defendants filed a motion to dismiss the amended complaint. On June 29, 2013, the court granted in part and denied in part the defendants’ motion. The Company and the other defendants intend to defend this lawsuit vigorously and believe the plaintiffs' claims are without merit. An estimate of reasonably possible losses associated with this action, if any, cannot be made at this time. 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

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•	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

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 and how those claims should be asserted on the Company’s behalf.

The Company and the individual defendants in the Hefner and Romano actions (the “State Shareholder Derivative Litigation”) moved to stay each of the actions in favor of the Federal Shareholder Derivative Litigation, in order to avoid duplicative proceedings, and also requested, in the alternative, the dismissal of the State Shareholder Derivative Litigation.

On June 19, 2013, the court stayed the Hefner action until at least November 29, 2013. The court subsequently lifted its stay for purposes of hearing and deciding the defendants’ respective motions to dismiss. On September 18, 2013, the court denied the defendants’ motions to dismiss. The parties have agreed to stay this action pending the review and investigation by the SLC of the claims alleged by the plaintiffs in the Federal Shareholder Derivative Litigation and in this action, and to determine whether and how those claims should be asserted on the Company’s behalf.

On May 8, 2013, the court stayed the Romano action pending further order of the court. On October 31, 2013, the plaintiff filed a motion to lift the stay, which was denied by the court on February 7, 2014. On October 29, 2014, the court granted plaintiff’s application to dismiss the action without prejudice.

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An estimate of reasonably possible losses associated with both the Federal Shareholder Derivative Litigation and the State Shareholder Derivative Litigation cannot be made at this time. The Company has not established any reserves relating to these actions.

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 SandRidge Energy, Inc. 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 (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. The defendants have filed respective motions to dismiss the consolidated amended complaint, which are pending before the court. 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 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. All of these motions are pending before the court.

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. 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.

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

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against the Company; however, any governmental action or resolution thereof could be material to the Company. The Company is cooperating with the investigation.

On November 10, 2014, a class action complaint was filed in the U. S. District Court for the Western District of Oklahoma against certain current and former directors and officers of the Company in the case styled Steve Surbaugh vs. SandRidge Energy, Inc., Tom L. Ward, James D. Bennett, Eddie M. LeBlanc, and Randall D. Cooley. The complaint asserts a federal securities class action on behalf of a putative class consisting of all persons other than defendants who purchased SandRidge securities between March 1, 2013, through November 4, 2014, seeking to recover damages allegedly caused by the defendants’ violations of federal securities laws under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder. The complaint alleges that, throughout the class period, the defendants made materially false and misleading statements regarding SandRidge’s business, operations and future prospects because such statements failed to properly account for the penalties SandRidge accrued under its treating agreement with Occidental Petroleum Corporation and, as a result, SandRidge’s financial statements were materially false and misleading during the class period. An estimate of reasonably possible losses associated with this action cannot be made at this time. The Company has not established any reserves relating to this action.

On November 11, 2014, a class action complaint was filed in the U. S. District Court for the Western District of Oklahoma against certain current and former directors and officers of the Company in the case styled Steven T. Dakil vs. SandRidge Energy, Inc., Tom L. Ward, James D. Bennett, and Eddie M. LeBlanc. The complaint asserts a federal securities class action on behalf of a putative class consisting of all persons other than defendants who purchased or otherwise acquired SandRidge securities between February 28, 2013, and November 3, 2014, seeking to recover damages allegedly caused by the defendants’ violations of federal securities laws under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, and Rule 10b-5 promulgated thereunder. The complaint alleges that, throughout the class period, defendants made materially false and misleading statements regarding SandRidge’s business, operational and compliance policies. Specifically, plaintiff alleges that defendants made false and/or misleading statements and/or failed to disclose that: (i) SandRidge was improperly accounting for penalties owed to Occidental Petroleum Corp. under a treating agreement on an annual basis when it was required to do so on a quarterly basis; (ii) SandRidge's quarterly and annual financial and operating results for the periods ending December 31, 2012 through June 30, 2014, were overstated and required restatement; (iii) defendant Ward engaged in improper related party transactions; (iv) SandRidge lacked proper internal controls over financial reporting; and (v) as a result of the foregoing, SandRidge’s financial statements were materially false and misleading during the class period.

On February 17, 2015, the U.S. District Court for the Western District of Oklahoma consolidated the Surbaugh and Dakil actions. An estimate of reasonably possible losses associated with this consolidated action cannot be made at this time. 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 March 31, 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 $8.5 million for the three-month period ended March 31, 2015. Based on current projected natural gas production levels, the Company expects to accrue between approximately $31.0 million

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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 $23.9 million total) that would be due in 2041 if the estimated shortfall for the three-month period ended March 31, 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 March 31, 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 $291.4 million for the contract years 2012 through 2019, which includes $83.6 million for penalties incurred through March 31, 2015. Further, by paying approximately $290.9 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.

Guarantees of Plugging and Abandonment Obligations

In conjunction with the sale of the Gulf Properties, the Company guaranteed on behalf of Fieldwood certain plugging and abandonment obligations associated with the Gulf Properties. The Company submitted a request for release of the guarantee to the Bureau of Ocean Energy Management on March 31, 2015 as permitted under the terms of the agreement. To date, the Company has paid no amounts under this guarantee. See Note 2 for additional information regarding the guarantees.

Risks and Uncertainties

Production targets contained in certain gathering and treating agreements 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, cash flows from operating activities and availability under the senior credit facility, 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, 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 would 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.

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11. Equity

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. All dividend payments to date on the Company’s 8.5%, 6.0% and 7.0% convertible perpetual preferred stock have been paid in cash. Paid and unpaid dividends included in the calculation of loss applicable to the Company’s common stockholders and the Company’s basic loss per share calculation for the three-month periods ended March 31, 2015 and 2014 as presented in the accompanying unaudited condensed consolidated statements of operations, are included in the tables below (in thousands):



	Three Months Ended March 31,
	2015						2014
	Dividends Paid		Dividends Unpaid		Total		Dividends Paid		Dividends Unpaid		Total
8.5% Convertible perpetual preferred stock	$	2,815	$	2,816	$	5,631	$	2,815	$	2,816	$	5,631
6.0% Convertible perpetual preferred stock	—		—		—		500		2,500		3,000
7.0% Convertible perpetual preferred stock	—		5,250		5,250		—		5,250		5,250
Total	$	2,815	$	8,066	$	10,881	$	3,315	$	10,566	$	13,881

In 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.

On April 1, 2015, the Company announced a semi-annual dividend of $3.50 per share on its 7.0% convertible perpetual preferred stock and stated its intent to pay such dividends with shares of the Company’s common stock on May 15, 2015.

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 three-month periods ended March 31, 2015 and 2014. These shares were accounted for as treasury stock when withheld and then immediately retired.



	Three Months Ended March 31,
	2015		2014
	(In thousands)
Number of shares withheld for taxes	719		609
Value of shares withheld for taxes	$	1,218	$	3,677

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 March 31, 2015 and December 31, 2014 was $2.5 million and is due in two equal installments in October 2015 and October 2016.

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Restricted Common Stock

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 consolidated statements of operations. For the three-month periods ended March 31, 2015 and 2014, the Company recognized equity compensation expense of $4.8 million and $7.4 million, net of $1.2 million and $1.9 million capitalized, respectively, related to restricted common stock.

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

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-month periods ended March 31, 2015 and 2014 (in thousands):



	Three Months Ended March 31,
	2015		2014
Current
Federal	$	—	$	—
State	40		127
	40		127
Deferred
Federal	—		—
State	—		—
	—		—
Total provision	40		127
Less: income tax provision attributable to noncontrolling interest	30		82
Total provision attributable to SandRidge Energy, Inc.	$	10	$	45

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 March 31, 2015. Thus the Company’s effective tax rate and tax expense for the three-month period ended March 31, 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 period.

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 March 31, 2015.

At both March 31, 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 2011 to present remain open for federal examination. Additionally, tax years 2005 through 2010 remain subject to examination for the purpose

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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.

13. Loss 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-month periods ended March 31, 2015 and 2014:



	Net Loss			Weighted Average Shares	Loss Per Share
	(In thousands, except per share amounts)
Three Months Ended March 31, 2015
Basic loss per share	$	(1,045,834	)	478,165	$	(2.19	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Convertible preferred stock(2)	—			—
Diluted loss per share	$	(1,045,834	)	478,165	$	(2.19	)
Three Months Ended March 31, 2014
Basic loss per share	$	(150,217	)	484,798	$	(0.31	)
Effect of dilutive securities
Restricted stock(3)	—			—
Convertible preferred stock(4)	—			—
Diluted loss per share	$	(150,217	)	484,798	$	(0.31	)

____________________


(1)	No incremental shares of potentially dilutive restricted stock awards or units included for the three-month period ended March 31, 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-month period ended March 31, 2015, were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.


(3)	Restricted stock awards covering 1.0 million shares for the three-month period ended March 31, 2014 were excluded from the computation of loss per share because their effect would have been antidilutive.


(4)	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 three-month period ended March 31, 2014, were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

See Note 11 for discussion 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 March 31, 2015 and December 31, 2014 are amounts totaling $2.7 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 stock 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	87		$	1.78
Vested	(1,948	)	$	6.92
Forfeited / Canceled	(205	)	$	6.14
Unvested restricted shares outstanding at March 31, 2015	6,490		$	6.18

As of March 31, 2015, the Company’s unrecognized compensation cost related to unvested restricted stock awards was $33.6 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 three-month period ended March 31, 2015, the Company granted restricted stock units that vest over two or four-year periods and will be settled in cash, shares of Company common stock or a combination of common stock and cash. The restricted stock units were valued based upon the Company’s period end common stock price, discounted using a credit spread (25.9% at March 31, 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.

Four-Year Restricted Stock Units. The following table presents a summary of the Company’s unvested restricted stock units which vest ratably over a four-year period from the date of grant. These restricted stock units 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.



	Number of Units		Fair Value per Unit at March 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	8,945
Vested	—
Forfeited / Canceled	(263	)
Unvested units outstanding at March 31, 2015	8,682		$	0.65	–	$	1.42

As of March 31, 2015, the Company’s unrecognized compensation cost related to unvested four-year restricted stock units was $8.1 million. Such cost is expected to be recognized over a weighted-average period of 3.9 years. The four-year restricted stock units are liability-classified awards.

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Two-Year Restricted Stock Units. The following table presents a summary of the Company’s unvested restricted stock units which vest over a two-year period (40% at the end of the first year and 60% at the end of the second year). These restricted stock units 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.



	Number of Units	Fair Value per Unit at March 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	2,398
Vested	—
Forfeited / Canceled	—
Unvested units outstanding at March 31, 2015	2,398	$	1.13	–	$	1.47

As of March 31, 2015, the Company’s unrecognized compensation cost related to unvested two-year restricted stock units was $3.0 million. Such cost is expected to be recognized over a weighted-average period of 1.75 years. The two-year restricted stock units are liability-classified awards.

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 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) 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 March 31, 2015 and December 31, 2014.



	March 31, 2015						December 31, 2014
Expected price volatility range	29.4	%	-	112.1		%	26.6	%	-	86.6		%
Weighted-average risk-free interest rate				0.4		%				0.5		%
Weighted-average fair value per unit				$	15.13					$	13.85

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Performance unit activity for the three-month period ended March 31, 2015 was as follows:



	Number of Performance Units
	(In thousands)
Outstanding at January 1, 2015	66
Granted	—
Forfeited /canceled	—
Outstanding at March 31, 2015	66

Performance period ending December 31, 2015
Vested	21
Unvested	7
Performance period ending December 31, 2016
Vested	13
Unvested	25

Performance Share Units. During the three-month period ended March 31, 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 during the three-month period ended March 31, 2015 and the related assumptions for all outstanding performance share units at March 31, 2015.



	March 31, 2015
Expected price volatility range	29.0	%	-	74.0		%
Weighted-average risk-free interest rate				0.8		%
Weighted-average fair value per unit				$	1.65

The following table presents a summary of the Company’s performance share units.



	Number of Performance Share Units
	(In thousands)
Outstanding at January 1, 2015	—
Granted	2,044
Forfeited /canceled	(59	)
Outstanding at March 31, 2015	1,985

Performance period ending December 31, 2017
Vested	—
Unvested	1,985

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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 column in the tables below includes 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			Midstream Services			All Other			Consolidated Total
Three Months Ended March 31, 2015
Revenues	$	195,743		$	24,629		$	21,529		$	967		$	242,868
Inter-segment revenue	(11		)	(14,784		)	(12,765		)	—			(27,560		)
Total revenues	$	195,732		$	9,845		$	8,764		$	967		$	215,308
Loss from operations	$	(1,054,158	)	$	(7,772	)	$	(3,873	)	$	(22,653	)	$	(1,088,456	)
Interest expense, net	(16		)	—			—			(62,826		)	(62,842		)
Other (expense) income, net	(454		)	(4		)	4			(82		)	(536		)
Loss before income taxes	$	(1,054,628	)	$	(7,776	)	$	(3,869	)	$	(85,561	)	$	(1,151,834	)
Capital expenditures(2)	$	302,062		$	1,875		$	8,432		$	7,822		$	320,191
Depreciation, depletion, amortization and accretion	$	107,211		$	5,760		$	2,679		$	4,884		$	120,534
At March 31, 2015
Total assets	$	5,301,850		$	103,668		$	221,048		$	430,639		$	6,057,205
Three Months Ended March 31, 2014
Revenues	$	407,338		$	47,080		$	46,294		$	969		$	501,681
Inter-segment revenue	—			(29,977		)	(28,648		)	—			(58,625		)
Total revenues	$	407,338		$	17,103		$	17,646		$	969		$	443,056
Loss from operations	$	(56,475	)	$	(3,102	)	$	(1,411	)	$	(21,342	)	$	(82,330	)
Interest income (expense), net	143			—			—			(62,186		)	(62,043		)
Other (expense) income, net	(185		)	(398		)	—			2,677			2,094
Loss before income taxes	$	(56,517	)	$	(3,500	)	$	(1,411	)	$	(80,851	)	$	(142,279	)
Capital expenditures(2)	$	264,243		$	620		$	5,957		$	4,954		$	275,774
Depreciation, depletion, amortization and accretion	$	121,041		$	7,711		$	2,441		$	5,260		$	136,453
At December 31, 2014
Total assets	$	6,273,802		$	115,083		$	219,691		$	650,649		$	7,259,225

____________________


(1)	Loss from operations includes a full cost ceiling limitation impairment of $1.1 billion and $164.8 million for the three-month periods ended March 31, 2015 and March 31, 2014, respectively.


(2)	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 March 31, 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 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



	March 31, 2015
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	6	$	1,799	$	10,016	$	—		$	11,821
Accounts receivable, net	7		270,150		38,887		(7		)	309,037
Intercompany accounts receivable	989,559		1,349,609		23,729		(2,362,897		)	—
Derivative contracts	—		209,059		25,749		(25,749		)	209,059
Prepaid expenses	—		9,888		5		—			9,893
Other current assets	—		7,299		—		—			7,299
Total current assets	989,572		1,847,804		98,386		(2,388,653		)	547,109
Property, plant and equipment, net	—		4,295,793		1,041,208		—			5,337,001
Investment in subsidiaries	5,668,757		162,892		—		(5,831,649		)	—
Derivative contracts	—		42,347		—		—			42,347
Other assets	118,419		17,582		649		(5,902		)	130,748
Total assets	$	6,776,748	$	6,366,418	$	1,140,243	$	(8,226,204	)	$	6,057,205
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	146,319	$	390,058	$	1,781	$	(7	)	$	538,151
Intercompany accounts payable	1,330,950		995,832		36,115		(2,362,897		)	—
Derivative contracts	—		25,868		—		(25,749		)	119
Deferred tax liability	64,517		—		—		—			64,517
Other current liabilities	—		4,846		—		—			4,846
Total current liabilities	1,541,786		1,416,604		37,896		(2,388,653		)	607,633
Investment in subsidiaries	962,846		171,903		—		(1,134,749		)	—
Long-term debt	3,376,480		—		—		(5,902		)	3,370,578
Asset retirement obligations	—		55,966		—		—			55,966
Other long-term obligations	77		16,034		—		—			16,111
Total liabilities	5,881,189		1,660,507		37,896		(3,529,304		)	4,050,288
Equity
SandRidge Energy, Inc. stockholders’ equity	895,559		4,705,911		1,102,347		(5,808,258		)	895,559
Noncontrolling interest	—		—		—		1,111,358			1,111,358
Total equity	895,559		4,705,911		1,102,347		(4,696,900		)	2,006,917
Total liabilities and equity	$	6,776,748	$	6,366,418	$	1,140,243	$	(8,226,204	)	$	6,057,205

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(Unaudited)



	December 31, 2014
	Parent		Guarantors		Non-Guarantors		Eliminations			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	—		4,987,281		1,227,776		—			6,215,057
Investment in subsidiaries	6,606,198		176,365		—		(6,782,563		)	—
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	$	1,354,874	$	(8,959,133	)	$	7,259,225
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	201,368	$	477,399	$	4,632	$	(7	)	$	683,392
Intercompany accounts payable	1,315,667		780,645		35,895		(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		1,314,347		(6,992,328		)	1,937,825
Noncontrolling interest	—		—		—		1,271,995			1,271,995
Total equity	1,937,825		5,677,981		1,314,347		(5,720,333		)	3,209,820
Total liabilities and equity	$	7,680,335	$	7,183,149	$	1,354,874	$	(8,959,133	)	$	7,259,225

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(Unaudited)

Condensed Consolidating Statements of Operations



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2015
Total revenues	$	—		$	192,520		$	22,796		$	(8	)	$	215,308
Expenses
Direct operating expenses	—			112,117			2,837			(8		)	114,946
General and administrative	56			35,219			874			—			36,149
Depreciation, depletion, amortization and accretion	—			109,853			10,681			—			120,534
Impairment	—			903,235			180,631			—			1,083,866
Gain on derivative contracts	—			(44,109		)	(5,718		)	—			(49,827		)
Gain on sale of assets	—			(1,900		)	(4		)	—			(1,904		)
Total expenses	56			1,114,415			189,301			(8		)	1,303,764
Loss from operations	(56		)	(921,895		)	(166,505		)	—			(1,088,456		)
Equity earnings from subsidiaries	(972,071		)	(49,621		)	—			1,021,692			—
Interest expense	(62,826		)	(16		)	—			—			(62,842		)
Other (expense) income, net	—			(539		)	3			—			(536		)
Loss before income taxes	(1,034,953		)	(972,071		)	(166,502		)	1,021,692			(1,151,834		)
Income tax expense	—			—			40			—			40
Net loss	(1,034,953		)	(972,071		)	(166,542		)	1,021,692			(1,151,874		)
Less: net loss attributable to noncontrolling interest	—			—			—			(116,921		)	(116,921		)
Net loss attributable to SandRidge Energy, Inc.	$	(1,034,953	)	$	(972,071	)	$	(166,542	)	$	1,138,613		$	(1,034,953	)

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(Unaudited)



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2014
Total revenues	$	—		$	379,050		$	64,093		$	(87	)	$	443,056
Expenses
Direct operating expenses	—			138,402			4,810			(87		)	143,125
General and administrative	148			36,947			1,443			—			38,538
Depreciation, depletion, amortization and accretion	—			120,577			15,876			—			136,453
Impairment	—			122,466			42,313			—			164,779
Loss on derivative contracts	—			34,102			8,389			—			42,491
Total expenses	148			452,494			72,831			(87		)	525,386
Loss from operations	(148		)	(73,444		)	(8,738		)	—			(82,330		)
Equity earnings from subsidiaries	(73,985		)	(2,777		)	—			76,762			—
Interest (expense) income	(62,186		)	143			—			—			(62,043		)
Other income, net	—			2,093			1			—			2,094
Loss before income taxes	(136,319		)	(73,985		)	(8,737		)	76,762			(142,279		)
Income tax expense	17			—			110			—			127
Net loss	(136,336		)	(73,985		)	(8,847		)	76,762			(142,406		)
Less: net loss attributable to noncontrolling interest	—			—			—			(6,070		)	(6,070		)
Net loss attributable to SandRidge Energy, Inc.	$	(136,336	)	$	(73,985	)	$	(8,847	)	$	82,832		$	(136,336	)

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(Unaudited)

Condensed Consolidating Statements of Cash Flows



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2015
Net cash (used in) provided by operating activities	$	(92,504	)	$	133,837		$	25,968		$	22,794		$	90,095
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(377,052		)	—			—			(377,052		)
Other	—			(38,436		)	4			39,448			1,016
Net cash (used in) provided by investing activities	—			(415,488		)	4			39,448			(376,036		)
Cash flows from financing activities
Proceeds from borrowings	420,000			—			—			—			420,000
Repayments of borrowings	(245,000		)	—			—			—			(245,000		)
Intercompany (advances) borrowings, net	(238,183		)	238,337			(154		)	—			—
Other	(14,775		)	43,715			(25,189		)	(62,242		)	(58,491		)
Net cash (used in) provided by financing activities	(77,958		)	282,052			(25,343		)	(62,242		)	116,509
Net (decrease) increase in cash and cash equivalents	(170,462		)	401			629			—			(169,432		)
Cash and cash equivalents at beginning of year	170,468			1,398			9,387			—			181,253
Cash and cash equivalents at end of period	$	6		$	1,799		$	10,016		$	—		$	11,821

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(Unaudited)



	Parent		Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended March 31, 2014
Net cash provided by (used in) operating activities	$	289,883	$	(262,831	)	$	65,742		$	(2,343	)	$	90,451
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—		(331,016		)	—			—			(331,016		)
Proceeds from sale of assets	—		706,158			—			1,208			707,366
Other	—		29,690			(80		)	(31,962		)	(2,352		)
Net cash provided by (used in) investing activities	—		404,832			(80		)	(30,754		)	373,998
Cash flows from financing activities
Other	75,193		(141,487		)	(66,271		)	33,097			(99,468		)
Net cash provided by (used in) financing activities	75,193		(141,487		)	(66,271		)	33,097			(99,468		)
Net increase (decrease) in cash and cash equivalents	365,076		514			(609		)	—			364,981
Cash and cash equivalents at beginning of year	805,505		1,013			8,145			—			814,663
Cash and cash equivalents at end of period	$	1,170,581	$	1,527		$	7,536		$	—		$	1,179,644

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(Unaudited)

18. Subsequent Events

Royalty Trust Distributions. On April 30, 2015, the Royalty Trusts announced quarterly distributions for the three-month period ended March 31, 2015. The following distributions are expected to be paid on or before May 29, 2015 to holders of record as of the close of business on May 15, 2015 (in thousands):



Royalty Trust	Total Distribution		Amount Distributed to Third-Party Unitholders
Mississippian Trust I	$	9,261	$	6,770
Permian Trust	27,221		25,200
Mississippian Trust II	10,815		9,005
Total	$	47,297	$	40,975

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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 Company’s 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-month periods ended March 31, 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.

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. 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. 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.

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 three-month period ended March 31, 2014 were as follows:



	Three Months Ended March 31, 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.

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Operational Activities

Operational activities for the three-month period ended March 31, 2015 include the following:


•	Total production for the three-month period ended March 31, 2015 was comprised of approximately 33.6% oil, 50.1% natural gas and 16.3% NGLs compared to 40.5% oil, 50.5% natural gas and 9.0% NGLs in the same period of 2014.


•	Mid-Continent properties contributed approximately 7.0 MMBoe or 88.5% of the Company’s total production, for the three-month period ended March 31, 2015, compared to approximately 4.7 MMBoe, or 66.2% for the three-month period ended March 31, 2014.


•	Reduced the total rigs drilling to 13 (no rigs drilling disposal wells) at March 31, 2015 from 35 (including 4 drilling disposal wells) at December 31, 2014 and March 31, 2014.


•	Drilled 94 wells, excluding salt water disposal wells, in the Mid-Continent area during the three-month period ended March 31, 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.

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.

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

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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 selling 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-month periods ended March 31, 2015 and 2014 are discussed below.

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-month periods ended March 31, 2015 and 2014 are shown in the table below:



	Three Months Ended March 31,
	2015		2014
Oil (per Bbl)	$	48.57	$	98.61
Natural gas (per Mcf)	$	2.81	$	4.72

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.

Saltwater Gathering and Disposal System. Included within the Company’s full cost pool is a saltwater gathering and disposal system that included over 1,100 miles of gathering lines and over 200 active disposal wells at March 31, 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-month periods ended March 31, 2015 and 2014.



	Three Months Ended March 31,
	2015			2014
Results (in thousands)
Revenues
Oil	$	120,234		$	279,929
NGL	18,950			27,589
Natural gas	56,548			97,798
Other	11			2,022
Inter-segment revenue	(11		)	—
Total revenues	195,732			407,338
Operating expenses
Production	90,004			107,486
Production taxes	4,514			7,807
Depreciation and depletion—oil and natural gas	106,107			115,185
Accretion of asset retirement obligations	1,080			5,746
Impairment	1,083,583			164,779
(Gain) loss on derivative contracts	(49,827		)	42,491
Gain on sale of assets	(8		)	—
Other operating expenses	14,437			20,319
Total operating expenses	1,249,890			463,813
Loss from operations	$	(1,054,158	)	$	(56,475	)

Production data
Oil (MBbls)	2,651			2,885
NGL (MBbls)	1,288			642
Natural gas (MMcf)	23,733			21,593
Total volumes (MBoe)	7,895			7,126
Average daily total volumes (MBoe/d)	87.7			79.2
Average prices—as reported(1)
Oil (per Bbl)	$	45.35		$	97.03
NGL (per Bbl)	$	14.71		$	42.97
Natural gas (per Mcf)	$	2.38		$	4.53
Total (per Boe)	$	24.79		$	56.88
Average prices—including impact of derivative contract settlements(2)
Oil (per Bbl)	$	88.23		$	95.86
NGL (per Bbl)	$	14.71		$	42.97
Natural gas (per Mcf)	$	3.36		$	4.05
Total (per Boe)	$	42.14		$	54.95

__________________


(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-month periods ended March 31, 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 March 31,
	2015			2014
	Production (MBoe)	% of Total		Production (MBoe)	% of Total
Mid-Continent	6,990	88.5	%	4,715	66.2	%
Gulf of Mexico / Gulf Coast	—	—	%	1,321	18.5	%
Permian Basin	419	5.3	%	538	7.6	%
Other - west Texas	486	6.2	%	552	7.7	%
Total	7,895	100.0	%	7,126	100.0	%

Revenues

Exploration and production segment revenues from oil, natural gas and NGL sales decreased $209.6 million, or 51.7%, for the three-month period ended March 31, 2015, from the same period in 2014. Approximately $224.4 million of the total net decrease was due to a decline in the average prices received for oil, natural gas and NGL production. This decrease was slightly offset by an increase of $14.8 million due to a 769 MBoe, or 10.8%, increase in combined production, stemming largely from the continued development of the Company’s Mid-Continent properties.

Operating Expenses

Production expense includes the costs associated with the Company’s exploration and production activities, including, but not limited to, lease operating expense and treating costs. Production expenses decreased $17.5 million, or 16.3%, for the three-month period ended March 31, 2015 compared to the same period in 2014 primarily due to a decrease in production costs per Boe. During the three-month period ended March 31, 2015, production expense was $11.40 per Boe, down from the comparable 2014 period rate of $15.08 per Boe, primarily as a result of the sale of the Gulf Properties in February 2014, which had higher production costs inherent with offshore operations.

Production taxes decreased by $3.3 million, or 42.2%, for the three-month period ended March 31, 2015, compared to the same period in 2014, primarily due to the decrease in oil, natural gas and NGL revenue. Production taxes as a percentage of oil, natural gas and NGL revenue increased to approximately 2.3% for the three-month period ended March 31, 2015 from 1.9% for the same period of 2014 as taxable production from the Mid-Continent in the 2015 period replaced non-taxable production from the Gulf Properties sold in February 2014.

Depreciation and depletion for the Company’s oil and natural gas properties decreased by $9.1 million for the three-month period ended March 31, 2015 compared to the same period in 2014, largely a result of a decrease in the depreciation and depletion rate per Boe to $13.44 for the three-month period ended March 31, 2015, from $16.16 for the three-month period ended March 31, 2014. The decrease in the depreciation and depletion rate is primarily due to (i) the sale of the Gulf Properties in February 2014, (ii) full cost ceiling impairment recorded in 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.

Accretion of asset retirement obligations decreased $4.7 million for the three-month period ended March 31, 2015, compared to the same period in 2014, primarily due to the assumption by the buyer of asset retirement obligations associated with the Gulf Properties sold in February 2014.

The Company incurred impairments of $1.1 billion and $164.8 million for the three-month periods ended March 31, 2015 and 2014, respectively. The 2015 impairment was due to a full cost ceiling limitation resulting primarily from the significant decrease in oil 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.

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of $(137.0) million and $23.4 million, respectively. Included in the net cash payments for the three months ended March 31, 2014 are $69.6 million of payments for 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 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-month periods ended March 31, 2015 and 2014.



	Three Months Ended March 31,
	2015			2014
Results (in thousands)
Revenues	$	24,629		$	47,080
Inter-segment revenue	(14,784		)	(29,977		)
Total revenues	9,845			17,103
Operating expenses	17,617			20,205
Loss from operations	$	(7,772	)	$	(3,102	)

Drilling rig statistics
Average number of operational rigs owned during the period	27.0			27.0
Average number of rigs working for third parties	—			5.5
Number of days drilling for third parties	—			494
Average drilling revenue per day per rig drilling for third parties(1)	$	—		$	15,107

Rig status - March 31	2015			2014
Working for SandRidge	4			12
Working for third parties	—			5
Idle(2)	21			10
Total operational	25			27
Non-operational(3)	2			3
Total rigs	27			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 March 31, 2015 were stacked and non-operational rigs at March 31, 2014 were held for sale.

Drilling and oil field services segment revenues and expenses decreased $7.3 million and $2.6 million, respectively for the three-month period ended March 31, 2015, compared to the same period in 2014, primarily due to a decrease in revenue from third-party working interests for work performed on wells in which the Company also has an interest, as well as a decrease in work performed for third parties during the three-month period ended March 31, 2015. Demand for the Company’s drilling and oilfield services in the Permian region declined significantly in the latter half of 2014 as a result of the Company’s fulfillment of its drilling obligation with the Permian Trust and the downward trend in oil prices that began during that period. At December 31, 2014, the Company determined the future use of its drilling and oilfield services assets in this region was limited and recorded an impairment of $24.3 million on these assets. During the three-month period ended March 31, 2015, the Company decided to discontinue all remaining drilling and oilfield services operations in the Permian region.

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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. Gas 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.

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 fees charged and volumes delivered by the electrical transmission system.

Set forth in the table below is financial and operational information for the midstream services segment for the three-month periods ended March 31, 2015 and 2014.



	Three Months Ended March 31,
	2015			2014
Results (in thousands)
Operating revenues	$	21,529		$	46,294
Inter-segment revenue	(12,765		)	(28,648		)
Total revenues	8,764			17,646
Operating expenses	12,637			19,057
Loss from operations	$	(3,873	)	$	(1,411	)

Gas Marketed
Volumes (MMcf)	1,723			1,813
Average price	$	2.64		$	4.72

Midstream services segment revenues and expenses decreased $8.9 million and $6.4 million, respectively, for the three-month period ended March 31, 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) a decrease of $2.08 per Mcf in the average price received for natural gas purchased and marketed in west Texas, and (iii) a decrease in gas compressor rentals.

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Consolidated Results of Operations

Revenues

The Company’s consolidated revenues for the three-month periods ended March 31, 2015 and 2014 are presented in the table below.



	Three Months Ended March 31,
	2015		2014
	(In thousands)
Revenues
Oil, natural gas and NGL	$	195,732	$	405,316
Drilling and services	9,845		17,080
Midstream and marketing	8,764		17,910
Other	967		2,750
Total revenues(1)	$	215,308	$	443,056

___________________


(1)	Includes $15.4 million and $44.2 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended March 31, 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 three-month periods ended March 31, 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-month periods ended March 31, 2015 and 2014 are presented below.



	Three Months Ended March 31,
	2015			2014
	(In thousands)
Expenses
Production	$	89,498		$	106,856
Production taxes	4,514			7,807
Cost of sales	12,827			12,481
Midstream and marketing	8,107			16,000
Depreciation and depletion—oil and natural gas	106,107			115,185
Depreciation and amortization—other	13,347			15,522
Accretion of asset retirement obligations	1,080			5,746
Impairment	1,083,866			164,779
General and administrative	36,149			38,538
(Gain) loss on derivative contracts	(49,827		)	42,491
Gain on sale of assets	(1,904		)	(19		)
Total expenses(1)	$	1,303,764		$	525,386

___________________

(1)

Includes $132.2 million and $20.2 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended March 31, 2015 and 2014, respectively. Expenses attributable to noncontrolling interests in consolidated VIEs include $127.0 million and $29.9 million of allocated full cost ceiling impairments for the three-month periods ended March 31, 2015 and 2014, respectively.

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

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

The Company’s other income (expense), taxes and net loss attributable to noncontrolling interest for the three-month periods ended March 31, 2015 and 2014 are presented in the table below.



	Three Months Ended March 31,
	2015			2014
	(In thousands)
Other income (expense)
Interest expense	$	(62,842	)	$	(62,043	)
Other (expense) income, net	(536		)	2,094
Total other expense	(63,378		)	(59,949		)
Loss before income taxes	(1,151,834		)	(142,279		)
Income tax expense	40			127
Net loss	(1,151,874		)	(142,406		)
Less: net loss attributable to noncontrolling interest	(116,921		)	(6,070		)
Net loss attributable to SandRidge Energy, Inc.	$	(1,034,953	)	$	(136,336	)

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Interest expense for the three-month periods ended March 31, 2015 and 2014 consisted of the following:



		Three Months Ended March 31,
		2015			2014
	(In thousands)
Interest expense
Interest expense on debt		$	63,771		$	63,658
Amortization of debt issuance costs, discounts and premium		2,367			2,490
Write off of debt issuance costs		2,221			—
Capitalized interest		(5,502		)	(3,825		)
Total		62,857			62,323
Less: interest income		(15		)	(280		)
Total interest expense		$	62,842		$	62,043

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.

Net loss attributable to noncontrolling interest represents the portion of net loss attributable to third-party ownership in the Company’s consolidated VIEs and subsidiaries. Net loss attributable to noncontrolling interest increased $110.9 million for three-month period ended March 31, 2015 from the same period in 2014, primarily due to a full cost ceiling impairment attributable to noncontrolling interest of $127.0 million for the three-month period ended March 31, 2015 compared to a full cost ceiling impairment attributable to noncontrolling interest of $29.9 million for the three-month period ended March 31, 2014. Additionally, revenues for the Royalty Trusts decreased in the 2015 period compared to the 2014 period 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. The decreases in income noted above were slightly offset by net gains recognized on the Royalty Trusts’ derivative contracts during the 2015 period compared to net losses recognized in the 2014 period.

Liquidity and Capital Resources

The Company’s primary sources of liquidity and capital resources are cash flows from operating activities, borrowings under the senior credit facility, proceeds from monetizations of assets and the issuance of equity and debt securities. Declines in oil and natural gas prices during the latter portion of 2014 and the first quarter of 2015 have had a negative effect on the Company’s cash flows from operations and sustained low oil prices will require the Company to incur additional indebtedness under its senior credit facility to fund planned capital expenditures and other 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 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, the payment of dividends on its outstanding convertible perpetual preferred stock if, and when, the Company elects to pay such dividends in cash, interest payments on its outstanding debt, and, from time to time, the repayment of long-term debt. The Company maintains access to funds that may be needed to meet capital funding requirements through its senior credit facility.

The Company’s 2015 plan for capital expenditures, including expenditures related to the Company’s drilling program for the Mississippian Trust II, is approximately $700.0 million, representing a 56% reduction from the Company’s actual capital expenditures in 2014. The Company expects to fund its near term capital and debt service requirements and working capital needs with cash flows from operations and available borrowing capacity under its senior credit facility. The senior credit facility has a borrowing base of $900.0 million, which had approximately $175.0 million and $235.0 million drawn at March 31, 2015 and May 1, 2015, respectively. On each such date, the Company had $11.6 million in outstanding letters of credit secured by the senior credit facility, which reduce availability under the senior credit facility on a dollar-for-dollar basis. The Company has no maturities of long-term debt prior to 2019, and 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 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

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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 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 $47.33 per Bbl in January 2015. Henry Hub natural gas prices declined from a monthly average of over $6.00 per MMBtu in February 2014 to $2.83 per MMBtu in March 2015. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows. The Company has in place fixed price swap and collar contracts for a majority of its anticipated oil production and a portion of its natural gas production in 2015 and for a portion of its anticipated oil production in 2016.

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, which would limit borrowings to fund capital expenditures. On February 23, 2015, the Company and its lenders amended the credit agreement to address the risk that, in light of depressed oil and natural gas prices, the Company would breach certain financial covenants in 2015. See additional discussion of the senior credit agreement amendment under “Cash Flows—Senior Credit Facility.” There is significant risk that the Company will be unable to comply with the financial covenants under its amended senior credit facility if the current levels of oil or natural gas prices continue for a prolonged period or if there are further sustained declines in such prices, without other mitigating circumstances. More specifically, absent changes in the 2015 capital expenditures program or consummation of transactions that reduce outstanding debt and/or increase the Company’s earnings before interest, taxes and depreciation, if oil or natural gas prices do not increase materially from the levels seen during the first quarter of 2015, the Company expects that it will not be able to comply with the covenant requiring it to maintain a ratio of total net debt to EBITDA below 6.25:1.00 at June 30, 2016. The failure to comply with the senior credit facility financial covenants, absent a waiver or amendment of the applicable provisions of the credit agreement by the lenders under the senior credit facility, could result in a default, which, if left uncured, could lead to an event of default under the senior credit facility. Such an event of default would permit the lenders under the senior credit facility to, among other things, terminate the commitments of each lender, require cash collateralization of outstanding letters of credit, and/or declare all outstanding loans immediately due and payable. An event of default would trigger cross-default under certain of the Company’s other financing instruments, including the indentures governing its Senior Notes. The application of any of the lender remedies under the credit facility could have a material adverse effect on the Company’s financial position.

In light of current commodity prices and the Company’s leverage position, the Company is analyzing 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 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. Such transactions, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

As of March 31, 2015, the Company’s cash and cash equivalents were $11.8 million, including $10.0 million attributable to the Company’s consolidated VIEs which is available to satisfy only obligations of the VIEs. The Company had approximately $3.4 billion in total debt outstanding and $11.6 million in outstanding letters of credit with $175.0 million outstanding under its senior credit facility at March 31, 2015. As of and during the three-month period ended March 31, 2015, the Company was in compliance with applicable covenants under its senior credit facility and outstanding Senior Notes. As of May 1, 2015, the Company’s cash and cash equivalents were approximately $8.7 million, including $8.7 million attributable to the Company’s consolidated VIEs. Additionally, there was $235.0 million outstanding under the Company’s senior credit facility and $11.6 million in outstanding letters of credit.

The Company is party to an agreement with Repsol under which the Company currently anticipates it 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 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. Absent any significant effects from its commodity derivative instruments, the Company maintains a working capital deficit or a relatively small amount of positive working capital because the Company’s capital spending generally exceeds the Company’s cash flows from operations.

At March 31, 2015, the Company had a working capital deficit of $60.5 million compared to a surplus of $47.5 million at December 31, 2014. Current assets decreased by $284.8 million and current liabilities decreased by $176.8 million at March 31, 2015, compared to December 31, 2014. The decrease in current assets is primarily due to a $169.4 million decrease in cash and cash equivalents, which is primarily the result of cash used in operations and for capital expenditures during the three-month period ended March 31, 2015. Also contributing to the decrease in current assets were decreases of $82.4 million in the net asset position of the Company’s current derivative contracts and $21.0 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 $145.2 million in accounts payable and accrued expenses largely due to (i) a reduction in accrued capital expenditures in conjunction with a decrease in the number of drilling rigs operating on the Company’s properties (ii) interest payments made on the Senior Notes, (iii) the payment of accrued 2014 bonuses and (iv) other changes due primarily to fluctuations in the timing and amount of the payment of expenditures related to exploration and production operations during the three-month period ended March 31, 2015.

Cash Flows

The Company’s cash flows for the three-month periods ended March 31, 2015 and 2014 are presented in the following table and discussed below:



	Three Months Ended March 31,
	2015			2014
	(In thousands)
Cash flows provided by operating activities	$	90,095		$	90,451
Cash flows (used in) provided by investing activities	(376,036		)	373,998
Cash flows provided by (used in) financing activities	116,509			(99,468		)
Net (decrease) increase in cash and cash equivalents	$	(169,432	)	$	364,981

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 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. Net cash flows provided by operating activities for the three-month period ended March 31, 2015 were consistent with the comparable period in 2014, primarily due to gains received on settlement of derivative contracts and, to a lesser extent, a reduction in operating expenses during the three-month period ended March 31, 2015, that largely offset declines in revenues from oil, natural gas and NGLs during the same period.

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.

Cash flows used in investing activities were $376.0 million for the three-month period ended March 31, 2015 compared to cash provided by investing activities of $374.0 million for the same period in 2014. During the three-month period ended March 31, 2015, cash flows used in investing activities primarily consisted of capital expenditures, excluding acquisitions. During the three-month period ended March 31, 2014, the Company received proceeds of $707.4 million primarily from the sale of the Gulf Properties, which were partially offset by capital expenditures during the period.

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Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the three-month periods ended March 31, 2015 and 2014 are summarized below:



	Three Months Ended March 31,
	2015		2014
	(In thousands)
Capital Expenditures
Exploration and production	$	302,062	$	264,243
Drilling and oil field services	1,875		620
Midstream services	8,432		5,957
Other	7,822		4,954
Capital expenditures, excluding acquisitions	320,191		275,774
Acquisitions	1,739		2,352
Total	$	321,930	$	278,126

Capital expenditures, excluding acquisitions, increased by $44.4 million for the three-month period ended March 31, 2015 from the same period in 2014 primarily due to an increase in drilling and leasehold expenditures in the Mid-Continent area. The number of drilling rigs operating on the Company’s properties decreased to 13 rigs at March 31, 2015 from 35 rigs at December 31, 2014. The Company has established a capital expenditures budget of $700.0 million for 2015 and anticipates the number of rigs operating on its properties to decline to seven rigs by mid-year 2015.

Cash Flows from Financing Activities

The Company’s financing activities provided $116.5 million of cash for the three-month period ended March 31, 2015 compared to $99.5 million used in the same period in 2014. The change is due primarily to net borrowings of $175.0 million under the senior credit facility during the three-month period ended March 31, 2015, as well as decreases of $9.4 million in noncontrolling interest distributions and $6.0 million in preferred dividends paid compared to the 2014 period. Additionally, during the three-month period ended March 31, 2014, the Company paid $44.1 million for the early settlement of financing derivatives as a result of the sale of the Gulf Properties, which was partially offset by proceeds from the sale of Royalty Trust units of $22.1 million.

Indebtedness

Long-term debt consists of the following at March 31, 2015 (in thousands):



Senior credit facility	$	175,000
Senior Notes
8.75% Senior Notes due 2020, net of $4,420 discount	445,580
7.5% Senior Notes due 2021, including premium of $3,372	1,178,372
8.125% Senior Notes due 2022	750,000
7.5% Senior Notes due 2023, net of $3,374 discount	821,626
Total debt	$	3,370,578

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-month period ended March 31, 2015, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Notes.

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Maturities of Long-Term Debt. Aggregate maturities of long-term debt, excluding premiums and discounts, for the next five fiscal years are as follows (in thousands):



2015	$	—
2016	—
2017	—
2018	—
2019	175,000
Thereafter	3,200,000
Total debt	$	3,375,000

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 February 23, 2015, in connection with an amendment to the senior credit agreement, the borrowing base was reduced to $900.0 million from $1.2 billion, which resulted in the write off of approximately $2.2 million of capitalized debt issuance costs. The next scheduled redetermination is expected to take place in October 2015. Quarterly, the Company pays a commitment fee assessed at an annual rate ranging from 0.375% to 0.5% on any available portion of the senior credit facility.

At March 31, 2015, the Company had $175.0 million outstanding under the senior credit facility and $11.6 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $713.4 million. As of and during the three-month period ended March 31, 2015, the Company was in compliance with all applicable financial covenants under the senior credit facility.

On February 23, 2015, the Company and its lenders amended the credit agreement to address the risk that, in light of depressed oil and natural gas prices, the Company would breach certain financial covenants in 2015. The amendment, among other things, (i) temporarily suspended until June 30, 2016 the financial covenant requiring maintenance of certain levels for the ratio of total net debt to EBITDA, (ii) adopted the financial covenants described below, (iii) permitted the incurrence of additional junior debt, which may be secured, in an amount not to exceed $500.0 million, and (iv) increased the applicable margin used in the calculation of interest under the senior credit facility.

The amended senior credit facility is available to be drawn on subject to limitations based on its terms and certain financial covenants, including maintenance of agreed upon levels for the (i) ratio of total debt secured by assets of the Company and certain of its subsidiaries to EBITDA, which may not exceed 2.25:1.00 at each quarter end, calculated using the last four completed fiscal quarters, (ii) ratio of EBITDA to interest expense, which must 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, (iii) ratio of current assets to current liabilities, which must be at least 1.00:1.00 at each quarter end, and (iv) ratio of total net debt to EBITDA, which may 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. If no amounts are drawn under the senior credit facility when calculating the ratio of total net debt to EBITDA, the Company’s debt is reduced by its cash balance in excess of $10.0 million. In 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 derivative contracts are disregarded.

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 $500.0 million, 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. At March 31, 2015, the Company had neither incurred junior debt nor entered into any intercreditor agreement.

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For more information about the senior credit facility and the Senior 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 three-month period ended March 31, 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 $175.1 million at March 31, 2015 compared to December 31, 2014, primarily due to net borrowings on the Company’s senior credit facility, which matures in 2019.

•

Drilling Carry Commitment. As of March 31, 2015, the Company had drilled 427 net wells under a drilling carry arrangement with Repsol and currently anticipates, due to changes in its drilling plan, that it will 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 ends May 31, 2015. As a result, the Company currently anticipates that it will carry a portion of Repsol’s drilling and completion costs for wells drilled in the future in the related area of mutual interest and will 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 the establishment of 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 Permian Properties 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 March 31, 2015. One contributing factor to the cumulative negative earnings position for the 36-month period ending March 31, 2015 is the $1.1 billion full cost ceiling impairment recorded on the Company’s oil and natural gas assets during the quarter ending March 31, 2015. 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 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

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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 March 31, 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.

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 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 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 March 31, 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 March 31, 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
April 2015 - December 2015	46,750	$	(0.30	)
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
April 2015 - December 2015	3,856	$77.20	$90.18	$103.55
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) loss on commodity derivative contracts of $(49.8) million and $42.5 million for the three-month periods ended March 31, 2015 and 2014, respectively, as reflected in the accompanying unaudited condensed consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(137.0) million and $23.4 million, respectively. Included in the net cash payments for the three-month period ended March 31, 2014 are $69.6 million of payments for 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 derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of the Company’s derivative transactions have an “investment grade” credit rating. The Company monitors on an ongoing basis the credit ratings of its derivative counterparties and considers its counterparties’ credit default risk ratings in determining the fair value of its derivative contracts. The Company’s 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 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 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 March 31, 2015, all of the Company’s open derivative contracts are with counterparties that share in the collateral supporting the Company’s senior credit facility. As a result, the Company is not required to post additional collateral under its derivative contracts. To secure their obligations under the derivative contracts

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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 27 financial institutions with commitments ranging from 0.15% to 6.00% of the borrowing base as of March 31, 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

The Company maintains disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), consisting of controls and other procedures designed to give reasonable assurance that information the Company is required to disclose in the reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including the Company’s Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding such required disclosure.

Management has determined that a material weakness in internal control over financial reporting as further described below continued to exist as of March 31, 2015. As a result of the determination of a material weakness in the Company’s internal control over financial reporting, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures were not effective as of March 31, 2015.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

We did not design and maintain effective internal controls because of the absence of a control over the accounting and valuation related to the appropriate interim period in which to record an amount, if any, for the annual CO₂ delivery shortfall penalty under the Company’s 30-year treating agreement with Occidental. Specifically, based on the prior method of accounting for such annual shortfall penalty, management did not evaluate whether an accrual for some or all of such annual penalty was needed within each quarterly period prior to the fourth quarter. Management concluded that this deficiency constituted a material weakness as defined in the Securities and Exchange Commission regulations. This material weakness resulted in the misstatement of accounts payable and accrued expenses and production expense in the prior interim periods and in the restatement of the unaudited interim periods ended June 30, 2014 and March 31, 2014 and for each of the interim periods in the year ended December 31, 2013. Additionally, this material weakness could result in a misstatement of the aforementioned account balances or disclosures that would result in a material misstatement to the interim consolidated financial statements that would not be prevented or detected.

Changes in Internal Control Over Financial Reporting

The Company has revised, clarified and implemented accounting policies and controls related to the shortfall penalty and, among other things, implemented controls for enhanced review of the Occidental penalty to determine if an accrual is appropriate during each interim period. These actions are subject to ongoing senior management review and Audit Committee oversight. There were no other changes in the Company’s internal control over financial reporting during the quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect the Company's internal control over financial reporting.

Management’s Remediation Initiatives

Management has tested the design of the internal controls related to the remediation of the material weakness described above and believes the foregoing efforts will effectively remediate the material weakness; however, such controls have not been in place and operating for a sufficient period of time to validate the remediation of the material weakness.

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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.

On August 4, 2011, Patriot Exploration, LLC, Jonathan Feldman, Redwing Drilling Partners, Mapleleaf Drilling Partners, Avalanche Drilling Partners, Penguin Drilling Partners and Gramax Insurance Company Ltd. filed a lawsuit against the Company, SandRidge Exploration and Production, LLC (“SandRidge E&P”) and certain current and former directors and senior executive officers of the Company (collectively, the “defendants”) in the U.S. District Court for the District of Connecticut. On October 28, 2011, the plaintiffs filed an amended complaint alleging substantially the same allegations as those contained in the original complaint. The plaintiffs allege that the defendants made false and misleading statements to U.S. Drilling Capital Management LLC and to the plaintiffs prior to the entry into a participation agreement among Patriot Exploration, LLC, U.S. Drilling Capital Management LLC and SandRidge E&P, which provided for the investment by the plaintiffs in certain of SandRidge E&P’s oil and natural gas properties. To date, the plaintiffs have invested approximately $16.0 million under the participation agreement. The plaintiffs seek compensatory and punitive damages and rescission of the participation agreement. On November 28, 2011, the defendants filed a motion to dismiss the amended complaint. On June 29, 2013, the court granted in part and denied in part the defendants’ motion. The Company and the other defendants intend to defend this lawsuit vigorously and believe the plaintiffs’ claims are without merit. An estimate of reasonably possible losses associated with this action, if any, cannot be made at this time. 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

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•	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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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 SandRidge Energy, Inc. 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 (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. The defendants have filed respective motions to dismiss the consolidated amended complaint, which are pending before the court. 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 the 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 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 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. 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.

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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ITEM 1A. Risk Factors

There has been no material change to the risk factors previously discussed in Item 1A—Risk Factors in the Company’s 2014 Form 10-K.

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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 March 31, 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)
January 1, 2015 — January 31, 2015	294,912	$	1.27	N/A	$	88.7
February 1, 2015 — February 28, 2015	410,871	$	2.00	N/A	$	88.7
March 1, 2015 — March 31, 2015	13,163	$	1.79	N/A	$	88.7
Total	718,946			—

____________________


(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/ EDDIE M. LEBLANC
		Eddie M. LeBlanc Executive Vice President and Chief Financial Officer

Date: May 7, 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	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	3/9/2009
10.1	Amendment No. 2 and Scheduled Determination of the Borrowing Base, dated as of February 23, 2015, to the Third Amended and Restated Credit Agreement among SandRidge Energy, Inc., Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer and the other lenders party thereto	10-K	001-33784	10.5.3	2/27/2015
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					*