SANDRIDGE ENERGY INC - Quarter Report: 2014 September (Form 10-Q)

Notional (MBbls)

Weighted Average
Fixed Price

October 2014 - December 2014

January 2015 - December 2015

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

__________________________

Form 10-Q

__________________________

(Mark One)



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

For the quarterly period ended September 30, 2014



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 December 31, 2014, was 484,828,817.

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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 amended Annual Report on Form 10-K/A for the fiscal year ended December 31, 2013 (the “2013 Form 10-K/A”) filed with the Securities and Exchange Commission (the “SEC”) on January 8, 2015.

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Preliminary Note

Immediately prior to filing this report, the Company filed a Form 10-K/A for the fiscal year ended December 31, 2013 and Forms 10-Q/A for the fiscal quarters ended March 31, 2014 and June 30, 2014, restating the Company’s financial statements for those periods. These filings were made to correct errors related to the accrual of the Company’s annual CO₂ under delivery shortfall penalties and to make certain other adjustments with respect to the periods covered by those reports. Certain details regarding those errors and adjustments are discussed in “Note 2 - Restatement of Previously Issued Financial Statements” of this Form 10-Q.

Restatement

On November 4, 2014, the Company filed a Current Report on Form 8-K, stating that (i) the consolidated financial statements of the Company for the periods ended December 31, 2013 and 2012 included in the Company’s Annual Reports on Form 10-K for the periods then ended and (ii) the unaudited consolidated financial statements of the Company for the periods ended March 31, 2013, June 30, 2013, September 30, 2013, March 31, 2014, and June 30, 2014 included in the Company’s Quarterly Reports on Form 10-Q for the periods then ended should no longer be relied upon due to potential changes related to the accrual of a liability associated with the under delivery by the Company of CO₂ to Occidental Petroleum Corporation’s (“Occidental”) Century Plant in Pecos County, Texas (the “Century Plant”) or elsewhere.

Historically, based on its determination of the appropriate method of accounting for the annual CO₂ delivery shortfall penalty, the Company did not evaluate whether an accrual was needed within each quarterly period prior to the fourth quarter. As a result of consultation with the staff of the SEC, the Company has determined to adopt a different method of accounting for the penalty, which method considers, on a quarterly basis, whether a portion of the annual shortfall delivery penalty should be accrued at the end of each quarter. After applying this method, the Company concluded that it should restate its previously issued unaudited condensed consolidated financial statements for the quarterly and year-to-date periods ended March 31, 2013, June 30, 2013, September 30, 2013, March 31, 2014, and June 30, 2014. The effect of such corrections is to transfer a portion of the annual accrual that was previously recorded at year-end to certain of the quarter-end periods within such calendar year. No changes are being made to the annual accruals previously recorded. For the three and nine-month periods ended September 30, 2013, the correction of these errors resulted in the accrual of (i) $8.3 million and $24.3 million in CO₂ under delivery shortfall penalties, respectively, which were previously included in the total 2013 annual delivery shortfall penalty of $32.7 million recorded in the fourth quarter of 2013. The correction of these errors in the unaudited condensed consolidated financial statements for the three and nine-month periods ended September 30, 2013 did not have any impact to the statement of operations or statement of cash flows for the year ended December 31, 2013 or to the balance sheet as of December 31, 2013.

Revision

Additionally, as a result of consultation with the staff of the SEC, the Company has determined that construction of the Century Plant under a construction contract with Occidental should have been accounted for under the full cost method of accounting rather than the completed contract method of accounting. As of December 31, 2013, this change in accounting treatment had no impact on total assets, total liabilities, net income or retained earnings, but resulted in certain equal and offsetting adjustments within current assets or current liabilities as of December 31, 2013.

See “Note 2 - Restatement of Previously Issued Financial Statements” of this Form 10-Q for more information regarding the impact of the above-described adjustments.

Internal Control Consideration

The Company’s management has determined that the absence of an evaluation of whether an accrual for the annual CO₂ delivery shortfall penalty was required within each quarterly period prior to the fourth quarter, in accordance with its prior method of accounting, was a deficiency in its internal control over financial reporting that constitutes a material weakness, as defined by SEC regulations, at September 30, 2014. For a discussion of management’s consideration of the Company’s disclosure controls and procedures and the material weakness identified, see Part I. Item 4 included in this Form 10-Q.

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SANDRIDGE ENERGY, INC.

FORM 10-Q

Quarter Ended September 30, 2014

INDEX



PART I. FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations (2013 periods restated)	6
	Condensed Consolidated Statement of Changes in Equity	7
	Condensed Consolidated Statements of Cash Flows (2013 period restated)	8
	Notes to Condensed Consolidated Financial Statements	9
ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	54
ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	72
ITEM 4.	Controls and Procedures	75

PART II. OTHER INFORMATION

ITEM 1.	Legal Proceedings	76
ITEM 1A.	Risk Factors	79
ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	80
ITEM 6.	Exhibits	80

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PART I. Financial Information

ITEM 1. Financial Statements

SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)



	September 30, 2014			December 31, 2013 (Revised)
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	590,246		$	814,663
Accounts receivable, net	330,543			349,218
Derivative contracts	53,919			12,779
Prepaid expenses	6,794			39,253
Other current assets	23,223			25,910
Total current assets	1,004,725			1,241,823
Oil and natural gas properties, using full cost method of accounting
Proved	11,252,074			10,972,816
Unproved	300,224			531,606
Less: accumulated depreciation, depletion and impairment	(6,250,457		)	(5,762,969		)
	5,301,841			5,741,453
Other property, plant and equipment, net	578,864			566,222
Derivative contracts	15,891			14,126
Other assets	77,068			121,171
Total assets	$	6,978,389		$	7,684,795

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS - Continued

(In thousands, except per share data)



	September 30, 2014			December 31, 2013 (Revised)
	(Unaudited)
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	652,649		$	812,488
Derivative contracts	—			34,267
Asset retirement obligations	—			87,063
Other current liabilities	18,549			—
Total current liabilities	671,198			933,818
Long-term debt	3,195,301			3,194,907
Derivative contracts	—			20,564
Asset retirement obligations	57,696			337,054
Other long-term obligations	16,418			22,825
Total liabilities	3,940,613			4,509,168
Commitments and contingencies (Note 12)
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 September 30, 2014 and December 31, 2013; aggregate liquidation preference of $265,000	3			3
6.0% Convertible perpetual preferred stock; 2,000 shares issued and outstanding at September 30, 2014 and December 31, 2013; aggregate liquidation preference of $200,000	2			2
7.0% Convertible perpetual preferred stock; 3,000 shares issued and outstanding at September 30, 2014 and December 31, 2013; aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value, 800,000 shares authorized; 491,262 issued and 490,224 outstanding at September 30, 2014 and 491,609 issued and 490,290 outstanding at December 31, 2013	483			483
Additional paid-in capital	5,292,874			5,298,301
Additional paid-in capital—stockholder receivable	(3,750		)	(3,750		)
Treasury stock, at cost	(6,823		)	(8,770		)
Accumulated deficit	(3,511,498		)	(3,460,462		)
Total SandRidge Energy, Inc. stockholders’ equity	1,771,294			1,825,810
Noncontrolling interest	1,266,482			1,349,817
Total equity	3,037,776			3,175,627
Total liabilities and equity	$	6,978,389		$	7,684,795

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013 (Restated)			2014			2013 (Restated)
	(Unaudited)
Revenues
Oil, natural gas and NGL	$	359,613		$	459,211		$	1,104,835		$	1,391,510
Drilling and services	21,348			16,149			57,280			49,597
Midstream and marketing	11,922			14,624			44,706			42,854
Construction contract	—			—			—			23,253
Other	1,224			3,619			5,056			11,066
Total revenues	394,107			493,603			1,211,877			1,518,280
Expenses
Production	82,664			124,571			256,473			389,911
Production taxes	8,380			8,816			24,027			24,819
Cost of sales	15,992			13,773			38,942			45,438
Midstream and marketing	11,405			13,224			40,659			39,954
Construction contract	—			—			—			23,253
Depreciation and depletion—oil and natural gas	112,569			137,639			325,021			434,068
Depreciation and amortization—other	14,417			15,270			45,350			46,628
Accretion of asset retirement obligations	1,116			8,472			7,927			28,051
Impairment	54			687			167,966			16,330
General and administrative	24,584			37,714			86,115			172,301
Employee termination benefits	5			2,256			8,927			120,374
(Gain) loss on derivative contracts	(132,575		)	132,808			(4,792		)	70,051
(Gain) loss on sale of assets	(995		)	539			(978		)	398,364
Total expenses	137,616			495,769			995,637			1,809,542
Income (loss) from operations	256,491			(2,166		)	216,240			(291,262		)
Other income (expense)
Interest expense	(59,783		)	(61,385		)	(183,689		)	(208,454		)
Loss on extinguishment of debt	—			—			—			(82,005		)
Other (expense) income, net	(273		)	658			3,159			1,163
Total other expense	(60,056		)	(60,727		)	(180,530		)	(289,296		)
Income (loss) before income taxes	196,435			(62,893		)	35,710			(580,558		)
Income tax (benefit) expense	(1,064		)	2,363			(2,131		)	7,300
Net income (loss)	197,499			(65,256		)	37,841			(587,858		)
Less: net income attributable to noncontrolling interest	40,161			16,191			49,733			9,393
Net income (loss) attributable to SandRidge Energy, Inc.	157,338			(81,447		)	(11,892		)	(597,251		)
Preferred stock dividends	11,381			13,881			39,144			41,644
Income available (loss applicable) to SandRidge Energy, Inc. common stockholders	$	145,957		$	(95,328	)	$	(51,036	)	$	(638,895	)
Income (loss) per share
Basic	$	0.30		$	(0.20	)	$	(0.11	)	$	(1.33	)
Diluted	$	0.27		$	(0.20	)	$	(0.11	)	$	(1.33	)
Weighted average number of common shares outstanding
Basic	485,458			483,582			485,194			480,209
Diluted	575,911			483,582			485,194			480,209

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)
Nine Months Ended September 30, 2014
Balance at December 31, 2013	7,650	$	8	490,290		$	483		$	5,294,551		$	(8,770	)	$	(3,460,462	)	$	1,349,817		$	3,175,627
Acquisition of ownership interest	—	—		—		—			(2,074		)	—			—			(656		)	(2,730		)
Sale of royalty trust units	—	—		—		—			4,091			—			—			18,028			22,119
Distributions to noncontrolling interest owners	—	—		—		—			—			—			—			(150,440		)	(150,440		)
Purchase of treasury stock	—	—		—		—			—			(6,281		)	—			—			(6,281		)
Retirement of treasury stock	—	—		—		—			(6,281		)	6,281			—			—			—
Stock distributions, net of purchases - retirement plans	—	—		281		—			(2,252		)	1,947			—			—			(305		)
Stock-based compensation	—	—		—		—			18,617			—			—			—			18,617
Stock-based compensation excess tax benefit	—	—		—		—			14			—			—			—			14
Issuance of restricted stock awards, net of cancellations	—	—		3,153		3			(3		)	—			—			—			—
Repurchase of common stock	—	—		(3,500	)	(3		)	(17,539		)	—			—			—			(17,542		)
Net (loss) income	—	—		—		—			—			—			(11,892		)	49,733			37,841
Convertible perpetual preferred stock dividends	—	—		—		—			—			—			(39,144		)	—			(39,144		)
Balance at September 30, 2014	7,650	$	8	490,224		$	483		$	5,289,124		$	(6,823	)	$	(3,511,498	)	$	1,266,482		$	3,037,776

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

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SANDRIDGE ENERGY, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)



	Nine Months Ended September 30,
	2014			2013 (Restated)
	(Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	37,841		$	(587,858	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization	370,371			480,696
Accretion of asset retirement obligations	7,927			28,051
Impairment	167,966			16,330
Debt issuance costs amortization	7,045			7,730
Amortization of discount, net of premium, on long-term debt	394			913
Loss on extinguishment of debt	—			82,005
Deferred income tax provision	—			4,702
(Gain) loss on derivative contracts	(4,792		)	70,051
Cash paid on settlement of derivative contracts	(48,816		)	(17,943		)
(Gain) loss on sale of assets	(978		)	398,364
Stock-based compensation	15,853			79,317
Other	488			1,499
Changes in operating assets and liabilities	(157,615		)	31,150
Net cash provided by operating activities	395,684			595,007
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(1,071,465		)	(1,163,539		)
Acquisition of assets	(16,920		)	(15,527		)
Proceeds from sale of assets	714,294			2,567,355
Net cash (used in) provided by investing activities	(374,091		)	1,388,289
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of borrowings	—			(1,115,500		)
Premium on debt redemption	—			(61,997		)
Debt issuance costs	—			(91		)
Proceeds from sale of royalty trust units	22,119			28,985
Noncontrolling interest distributions	(150,440		)	(153,002		)
Acquisition of ownership interest	(2,730		)	—
Stock-based compensation excess tax benefit	14			(4		)
Purchase of treasury stock	(8,278		)	(31,270		)
Repurchase of common stock	(17,542		)	—
Dividends paid — preferred	(45,025		)	(45,025		)
Cash (paid) received on settlement of financing derivative contracts	(44,128		)	5,099
Net cash used in financing activities	(246,010		)	(1,372,805		)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(224,417		)	610,491
CASH AND CASH EQUIVALENTS, beginning of year	814,663			309,766
CASH AND CASH EQUIVALENTS, end of period	$	590,246		$	920,257
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(209,939	)	$	(248,233	)
Cash paid for income taxes	$	(543	)	$	(2,911	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	—		$	(255,000	)
Change in accrued capital expenditures	$	(49,072	)	$	65,087
Asset retirement costs capitalized	$	3,398		$	4,145

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 system, an electrical transmission system and a drilling and related oil field services business.

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

Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from 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 4 for discussion of the Company’s significant associated VIEs.

Interim Financial Statements. The accompanying unaudited condensed consolidated financial statements as of December 31, 2013 have been derived from the audited financial statements contained in the Company’s amended Annual Report on Form 10-K/A (“2013 Form 10-K/A”) filed on January 8, 2015. The unaudited 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 2013 Form 10-K/A. 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, unless otherwise disclosed herein, are necessary to state fairly the 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 2013 Form 10-K/A.

Significant Accounting Policies. For a description of the Company’s significant accounting policies, see Note 1 of the consolidated financial statements included in the 2013 Form 10-K/A.

Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Company’s previously reported results of operations.

Restatement and Revision of Prior Period Financial Statements. See Note 2 “Restatement of Previously Issued Financial Statements” for a discussion of changes made during the third quarter of 2014 to the accompanying prior period unaudited condensed consolidated financial statements.

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.

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SANDRIDGE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

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.

Recent Accounting Pronouncements Not Yet Adopted. In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), 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 ASU 2014-09 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.

2. Restatement of Previously Issued Financial Statements

Overview

The Company has determined there were errors in the timing of its accrual of annual CO₂ delivery shortfall penalties incurred under its 30-year treating agreement with Occidental Petroleum Corporation (“Occidental”) and has determined that these errors were material to previously issued unaudited condensed consolidated financial statements for the three and nine-month periods ended September 30, 2013. For the three and nine-month periods ended September 30, 2013, the correction of these errors resulted in the accrual of $8.3 million and $24.3 million in CO₂ under delivery shortfall penalties, for the three and nine-month periods ended September 30, 2013, respectively, which were previously included in the total 2013 annual delivery shortfall penalty of $32.7 million recorded in the fourth quarter of 2013. As a result, these statements have been presented on a restated and amended basis herein. The correction of these errors in the financial statements for the three and nine-month periods ended September 30, 2013 did not have any impact on the statement of operations or statement of cash flows for the year ended December 31, 2013 or to the balance sheet as of December 31, 2013.

Additionally, the Company has made certain revisions to its condensed consolidated balance sheets as of December 31, 2013 in order to account for activities associated with construction of the Century Plant in Pecos County, Texas (the “Century Plant”) under the full cost method of accounting. The Company has determined that these revisions are not material to the originally issued financial statements; however, in conjunction with the Company’s need to restate its financial statements as a result of the error noted above, the Company has determined that it would be appropriate to make such revisions. The condensed consolidated balance sheet as of December 31, 2013 presented herein is consistent with the revised consolidated balance sheet included in the Company’s 2013 Form 10-K/A.

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Financial Statement Presentation

In addition to the restatement of the Company’s unaudited condensed consolidated financial statements, certain information within the following notes to the unaudited condensed consolidated financial statements has been restated and/or revised to reflect the corrections presented in the tables below or to add disclosure language, as appropriate.


•	Note 6. Property, Plant and Equipment


•	Note 12. Commitment and Contingencies


•	Note 15. Earnings (Loss) Per Share


•	Note 18. Business Segment Information


•	Note 19. Condensed Consolidating Financial Information

Condensed Consolidated Statements of Operations. The following table presents the impact of the error corrections on the Company’s previously reported unaudited condensed consolidated statements of operations for the three and nine-month periods ended September 30, 2013 (in thousands):



	Three Months Ended September 30, 2013						Nine Months Ended September 30, 2013
	As Reported			As Restated			As Reported			As Restated
Production	$	116,317		$	124,571		$	365,629		$	389,911
Total expenses	$	487,515		$	495,769		$	1,785,260		$	1,809,542
Income (loss) from operations	$	6,088		$	(2,166	)	$	(266,980	)	$	(291,262	)
(Loss) before income taxes	$	(54,639	)	$	(62,893	)	$	(556,276	)	$	(580,558	)
Net (loss)	$	(57,002	)	$	(65,256	)	$	(563,576	)	$	(587,858	)
Net loss attributable to SandRidge Energy, Inc.	$	(73,193	)	$	(81,447	)	$	(572,969	)	$	(597,251	)
Loss applicable to SandRidge Energy, Inc. common stockholders	$	(87,074	)	$	(95,328	)	$	(614,613	)	$	(638,895	)
Loss per share
Basic	$	(0.18	)	$	(0.20	)	$	(1.28	)	$	(1.33	)
Diluted	$	(0.18	)	$	(0.20	)	$	(1.28	)	$	(1.33	)

Condensed Consolidated Statement of Cash Flows. The following table presents the impact of the error corrections on the Company’s previously reported unaudited condensed consolidated statement of cash flows for the nine-month period ended September 30, 2013 (in thousands):



	Nine Months Ended September 30, 2013
	As Reported			As Restated
Net loss	$	(563,576	)	$	(587,858	)
Changes in operating assets and liabilities	$	6,868		$	31,150

Condensed Consolidated Balance Sheet. The Company has determined that unreimbursed costs incurred by the Company on behalf of Occidental during construction of the Century Plant that were previously presented as costs in excess of billings and contract loss should have been presented under the full cost method of accounting as an account receivable. Accordingly, the Company has revised the condensed consolidated balance sheet as of December 31, 2013 to reflect this presentation. This revision did not have any impact to total current assets as of December 31, 2013.

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The following table presents the impact of these adjustments on the Company’s previously reported condensed consolidated balance sheet as of December 31, 2013 (in thousands):



	Year Ended December 31, 2013
	As Reported		As Revised
Current assets
Costs in excess of billings and contract loss	$	4,079	$	—
Other current assets	$	21,831	$	25,910

3. Divestitures

Sale of Permian Properties

On February 26, 2013, the Company sold all of its oil and natural gas properties in the Permian Basin in west Texas, excluding the assets attributable to the SandRidge Permian Trust’s (the “Permian Trust”) area of mutual interest, (the “Permian Properties”) for $2.6 billion. This transaction resulted in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded a $398.9 million loss on the sale for the nine-month period ended September 30, 2013. The loss is included in (gain) loss on sale of assets in the accompanying unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2013. The loss was calculated based on a comparison of proceeds received and the asset retirement obligations attributable to the Permian Properties that were assumed by the buyer to the sum of (i) an allocation of the historical net book value of the Company’s proved oil and natural gas properties attributable to the Permian Properties, (ii) the historical cost of unproved acreage sold and (iii) costs incurred by the Company to sell these properties. The allocated net book value attributable to the Permian Properties was calculated based on the relative fair value of the Permian Properties and the remaining proved oil and natural gas properties retained by the Company as of the date of sale. A portion of the loss, totaling $71.7 million, was allocated to noncontrolling interests and is reflected in net income attributable to noncontrolling interest in the accompanying unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2013.

The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2013 (in thousands):



	Nine Months Ended September 30, 2013(1)
Revenues	$	68,027
Direct operating expenses	$	17,453

__________________


(1)	Includes revenues and direct operating expenses through February 26, 2013, the date of sale.

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”) 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 to Fieldwood Energy LLC (“Fieldwood”). 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 16 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 September 30, 2014, the fair value of the guarantees was approximately $10.4 million. See Note 5 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

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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. Additionally, Fieldwood will maintain, for a period of up to one year from the closing date, restricted deposits totaling approximately $28.0 million held in escrow for plugging and abandonment obligations associated with the Gulf Properties. Upon expiration of the guarantees, the Company will receive payment from Fieldwood for half of such restricted deposits, or approximately $14.0 million. A receivable for this amount is included in other current assets in the accompanying unaudited condensed consolidated balance sheet at September 30, 2014.

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 September 30, 2013 and the nine-month periods ended September 30, 2014 and 2013 (in thousands):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2013		2014(1)		2013
Revenues	$	153,315	$	90,920	$	498,590
Expenses	$	126,137	$	63,674	$	377,529

____________________


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

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4. 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 three Delaware statutory trusts. SandRidge Mississippian Trust I (the “Mississippian Trust I”), the Permian Trust and SandRidge Mississippian Trust II (the “Mississippian Trust II”) (each individually, a “Royalty Trust” and collectively, the “Royalty Trusts”) completed initial public offerings of their common units in April 2011, August 2011 and April 2012, respectively. Concurrent with the closing of each offering, the Company conveyed certain royalty interests to each Royalty Trust in exchange for the net proceeds of the offering and units representing beneficial interests in the Royalty Trust. Royalty interests conveyed to the Royalty Trusts are in existing wells and wells to be drilled on oil and natural gas properties leased by the Company in defined areas of mutual interest. The following table summarizes information about each Royalty Trust as of September 30, 2014:



	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(1)	—	13,125,000	12,431,250
Liquidation date(2)	12/31/2030	3/31/2031	12/31/2031

____________________


(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)	At the time each Royalty Trust terminates, 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.

The Royalty Trusts make quarterly cash distributions to unitholders based on calculated distributable income. In order to provide support for cash distributions on the common units, the Company agreed to subordinate a portion of the units it owns in each Royalty Trust (the “subordinated units”), which constitute 25% of the total outstanding units of each Royalty Trust. The subordinated units 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. In exchange for agreeing to subordinate a portion of its Royalty Trust 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.

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The Royalty Trusts declared and paid quarterly distributions during the three and nine-month periods ended September 30, 2014 and 2013 as follows (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014(1)		2013(1)		2014(2)		2013(2)
Total distributions	$	56,191	$	81,594	$	184,176	$	226,404
Distributions to third-party unitholders	$	47,298	$	54,287	$	150,440	$	153,002

____________________


(1)	Subordination thresholds were not met for the Mississippian Trust I’s distributions for the three-month periods ended September 30, 2014 and 2013 and for the Mississippian Trust II’s distributions for the three-month period ended September 30, 2014, resulting in reduced distributions to the Company on its subordinated units for these periods.


(2)	Subordination thresholds were not met for the Mississippian Trust I’s distributions for the nine-month period ended September 30, 2014 and for the Permian Trust’s distribution for the nine-month period ended September 30, 2013, resulting in reduced distributions to the Company on its subordinated units for these periods.

See Note 20 for discussion of the Royalty Trusts’ distributions announced in October 2014.

Pursuant to the trust agreements governing the Royalty Trusts, SandRidge has committed to loan funds to each Royalty Trust on an unsecured basis, with terms substantially the same as would be obtained in an arm’s length transaction between SandRidge and an unaffiliated party, if at any time the Royalty Trust’s cash is not sufficient to pay ordinary course administrative expenses as they become due. Any funds loaned may not be used to satisfy indebtedness of the Royalty Trust or to make distributions. There were no amounts outstanding under the loan commitments at September 30, 2014 or December 31, 2013.

The Company and one of its wholly owned subsidiaries entered into a development agreement with each Royalty Trust that obligates the Company to drill, or cause to be drilled, a specified number of wells within respective areas of mutual interest, which are also subject to the royalty interests granted to the Mississippian Trust I, the Permian Trust and the Mississippian Trust II, by December 31, 2015, March 31, 2016 and December 31, 2016, respectively. 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 will automatically convert into common units on a one-for-one basis and the Company’s right to receive incentive distributions will terminate. On July 1, 2014, the Mississippian Trust I’s subordinated units, all of which were held by SandRidge, converted to common units. The newly-converted units remained subject to the distribution subordination thresholds through the Mississippian Trust I’s August 29, 2014 distribution. Beginning with the distribution made in November 2014, all of the Mississippian Trust I’s common units will share equally in its distribution. The Company continues to consolidate the activities of the Mississippian Trust I as its primary beneficiary subsequent to this conversion due to the Company’s original participation in the design of the Mississippian Trust I and continued (a) power to direct the activities that most significantly impact the economic performance of the Royalty Trust and (b) obligation to absorb losses and right to receive residual returns through its variable interests in the Royalty Trust, including ownership of common units, that could potentially be significant to the Mississippian Trust I.

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 will be drilled in order to secure the estimated amount of drilling costs for the Royalty Trust’s interests in the wells. As the Company fulfills its drilling obligation to each Royalty Trust, development wells that have been drilled and perforated for completion are released from the lien and the total amount that may be recovered by each Royalty Trust is proportionately reduced. As of September 30, 2014, the total maximum amount recoverable by the Permian Trust and the Mississippian Trust II under the remaining liens was approximately $31.6 million. The Company fulfilled its drilling obligation to the Mississippian Trust I in the second quarter of 2013 and the related lien was released.

Additionally, the Company and each Royalty Trust entered into an administrative services agreement, 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. The Company also entered into 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. Substantially concurrent with the execution of the derivatives agreements with the Permian Trust and the Mississippian Trust II, the Company novated certain of the derivative contracts underlying the respective derivatives agreements to each of these Royalty Trusts. The Company novated additional derivative contracts underlying the derivatives agreements to the Permian Trust in April 2012 and to the Permian Trust and the Mississippian Trust II in March 2013. The tables below present the open oil and natural gas

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commodity derivative contracts at September 30, 2014 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
October 2014 - December 2014	236	$	4.00	—	$	7.78
January 2015 - December 2015	1,010	$	4.00	—	$	8.55

Oil Price Swaps Underlying the Derivatives Agreements and Novated to the Royalty Trusts

See Note 10 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

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 fulfills its drilling obligations to the Royalty Trusts 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 subordinated units, that could potentially be significant to the Royalty Trusts. As a result, the Company consolidates the activities of the Royalty Trusts into its results of operations. Amounts attributable to the common units of the Royalty Trusts owned by third parties are reflected as noncontrolling interest in the consolidated financial statements.

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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 both September 30, 2014 and December 31, 2013, $1.3 billion of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheets was attributable to the Royalty Trusts. The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheets at September 30, 2014 and December 31, 2013 consisted of the following (in thousands):



	September 30, 2014			December 31, 2013
Cash and cash equivalents(1)	$	7,584		$	7,912
Accounts receivable, net	17,698			22,540
Derivative contracts	5,991			4,983
Total current assets	31,273			35,435
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion and impairment(3)	(272,346		)	(186,095		)
	1,053,596			1,139,847
Derivative contracts	—			1,476
Total assets	$	1,084,869		$	1,176,758
Accounts payable and accrued expenses	$	3,049		$	3,393
Total liabilities	$	3,049		$	3,393

____________________


(1)	Includes $3.0 million held by the trustee at September 30, 2014 and December 31, 2013 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)	Accumulated depletion and impairment at September 30, 2014 includes full cost ceiling limitation impairment allocated to the Royalty Trusts of $42.3 million. There was no full cost ceiling limitation impairment allocated to the Royalty Trusts as of December 31, 2013.

During the nine-month period ended September 30, 2014, the Company sold Permian Trust common units it owned in a transaction exempt from registration pursuant to Rule 144 under the Securities Act for proceeds of approximately $22.1 million. The sale was accounted for as an equity transaction with no gain or loss recognized. The Company continues to be the primary beneficiary of the Permian Trust after consideration of this transaction and continues to consolidate the activities of the Permian Trust as well as the activities of the Mississippian Trust I and Mississippian Trust II. The Company’s beneficial interests in the Royalty Trusts at September 30, 2014 and December 31, 2013 were as follows:



	September 30, 2014		December 31, 2013
Mississippian Trust I	26.9	%	26.9	%
Permian Trust	25.0	%	28.5	%
Mississippian Trust II	37.6	%	37.6	%

See Note 12 for discussion of the Company’s legal proceedings to which the Mississippian Trust I and Mississippian Trust II are also parties.

Grey Ranch Plant, L.P. Primarily engaged in treating and transportation of natural gas, Grey Ranch Plant, L.P. (“GRLP”) was a limited partnership that operated the Company’s Grey Ranch plant (the “Plant”) located in Pecos County, Texas. As of December 31, 2013, the Company owned a 50% interest in GRLP, which represented a variable interest. Income or loss of GRLP was allocated to the partners based on ownership percentage and any operating or cash shortfalls required contributions from the partners. GRLP was considered a VIE because certain equity holders lacked the ability to participate in decisions impacting GRLP. Agreements related to the ownership and operation of GRLP provided for GRLP to pay management fees to the Company to operate the Plant and lease payments for the Plant. Under the operating agreements, lease payments were reduced if throughput

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volumes were below those expected. The Company determined that it was the primary beneficiary of GRLP as it had both (i) the power, as operator of the Plant, to direct the activities of GRLP that most significantly impact its economic performance and (ii) the obligation to absorb losses, as a result of the operating and gathering agreements, that could potentially be significant to GRLP and, therefore, consolidated the activity of GRLP in its consolidated financial statements. The 50% ownership interest not held by the Company as of December 31, 2013 is presented as noncontrolling interest in the accompanying unaudited condensed consolidated financial statements. In the first quarter of 2014, one of the Company’s wholly owned subsidiaries acquired from a third party the remaining 50% ownership interest of GRLP. 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.

Prior to the Company’s acquisition of the remaining ownership of GRLP in the first quarter of 2014, GRLP’s assets could only be used to settle its own obligations and not other obligations of the Company and GRLP’s creditors had no recourse to the general credit of the Company. At December 31, 2013, $0.7 million of noncontrolling interest in the accompanying unaudited condensed consolidated balance sheet was related to GRLP. GRLP’s assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying unaudited condensed consolidated balance sheet at December 31, 2013 consisted of the following (in thousands):



	December 31, 2013
Cash and cash equivalents	$	132
Accounts receivable, net	16
Prepaid expenses	32
Other current assets	109
Total current assets	289
Other property, plant and equipment, net	1,163
Total assets	$	1,452

Accounts payable and accrued expenses	$	129
Total liabilities	$	129

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Grey Ranch Plant Genpar, LLC. As of December 31, 2013, the Company owned a 50% interest in Grey Ranch Plant Genpar, LLC (“Genpar”), the managing partner and 1% owner of GRLP. The Company served as Genpar’s administrative manager. Genpar’s ownership interest in GRLP was its only asset. As managing partner of GRLP, Genpar had the sole right to manage, control and conduct the business of GRLP. However, Genpar was restricted from making certain major decisions, including the decision to remove the Company as operator of the Plant. The rights afforded the Company under the Plant operating agreement and the restrictions on Genpar limited Genpar’s ability to make decisions on behalf of GRLP. Therefore, Genpar was considered a VIE. Although both the Company and Genpar’s other equity owner shared equally in Genpar’s economic losses and benefits and also had agreements that may be considered variable interests, the Company determined it was the primary beneficiary of Genpar due to (i) its ability, as administrative manager and operator of the Plant, to direct the activities of Genpar that most significantly impacted its economic performance and (ii) its obligation or right, as operator of the Plant, to absorb the losses of or receive benefits from Genpar that could potentially have been significant to Genpar. As the primary beneficiary, the Company consolidated Genpar’s activity. However, its sole asset, the investment in GRLP, was eliminated in consolidation. Genpar had no liabilities. In the first quarter of 2014, one of the Company’s wholly owned subsidiaries acquired from a third party the remaining 50% ownership interest of Genpar. Because the Company was the primary beneficiary and consolidated Genpar, 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, Genpar is no longer considered a VIE for reporting purposes.

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

Amounts due from and due to PGC as of September 30, 2014 and December 31, 2013 included in the accompanying unaudited condensed consolidated balance sheets are as follows (in thousands):



	September 30, 2014		December 31, 2013
Accounts receivable due from PGC	$	1,089	$	741
Accounts payable due to PGC	$	4,006	$	3,634

5. 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

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Company has assets and liabilities classified as Level 1, Level 2 and Level 3 as of September 30, 2014 or December 31, 2013, as described below.

Level 1 Fair Value Measurements

Restricted deposits. The fair value of restricted deposits invested in mutual funds or municipal bonds is based on quoted market prices. For restricted deposits held in savings accounts, carrying value approximates fair value. Restricted deposits are included in other assets in the accompanying unaudited condensed consolidated balance sheet at December 31, 2013. There were no restricted deposits outstanding at September 30, 2014.

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.

Level 2 Fair Value Measurements

Derivative contracts. The fair values of the Company’s oil and natural gas fixed price swaps and 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 3, 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 expiration of the guarantee by February 25, 2015 (3.71% at September 30, 2014). 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 September 30, 2014 is included in the table below (in thousands).



Unobservable Input
Estimated future payments for plugging and abandonment	$	426,661

Derivative contracts. The fair value of the Company’s oil basis swaps outstanding during the nine-month period ended September 30, 2013 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 oil basis swaps was the estimate of future oil basis differentials. Significant increases (decreases) in oil basis differentials could have resulted in a significantly higher (lower) fair value measurement. All of the oil basis swaps outstanding during 2013 contractually matured during the nine-month period ended September 30, 2013.

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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):

September 30, 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	$	—	$	69,810	$	—	$	—	$	69,810
Investments	10,389		—		—		—		10,389
	$	10,389	$	69,810	$	—	$	—	$	80,199
Liabilities
Guarantees	$	—	$	—	$	10,430	$	—	$	10,430
Commodity derivative contracts	—		—		—		—		—
	$	—	$	—	$	10,430	$	—	$	10,430

December 31, 2013



	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3		Netting(1)			Assets/Liabilities at Fair Value
Assets
Restricted deposits	$	27,955	$	—	$	—	$	—		$	27,955
Commodity derivative contracts	—		50,274		—		(23,369		)	26,905
Investments	13,708		—		—		—			13,708
	$	41,663	$	50,274	$	—	$	(23,369	)	$	68,568
Liabilities
Commodity derivative contracts	$	—	$	78,200	$	—	$	(23,369	)	$	54,831
	$	—	$	78,200	$	—	$	(23,369	)	$	54,831

____________________

(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 and nine-month periods ended September 30, 2014 (in thousands):



Level 3 Fair Value Measurements - Guarantees	Three Months Ended September 30, 2014			Nine Months Ended September 30, 2014
Beginning balance	$	12,028		$	—
Issuances(1)	—			9,446
(Gain) loss on guarantees	(1,598		)	984
Ending balance	$	10,430		$	10,430

____________________


(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.

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 3 for discussion of the sale of the Gulf Properties. The fair value of the guarantees as of September 30, 2014 is included in other current liabilities in the accompanying unaudited condensed consolidated balance sheet.

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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 nine-month period ended September 30, 2013 (in thousands):



Level 3 Fair Value Measurements - Commodity Derivative Contracts	Nine Months Ended September 30, 2013
Beginning balance	$	(512	)
Loss on derivative contracts	(133		)
Settlements paid	645
Ending balance	$	—

There were no outstanding Level 3 commodity derivative contracts at September 30, 2014 or 2013.

See Note 10 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 and nine-month periods ended September 30, 2014 and 2013, 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 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 September 30, 2014 and December 31, 2013 were as follows (in thousands):



	September 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
8.75% Senior Notes due 2020(1)	$	454,500	$	445,232	$	486,000	$	444,736
7.5% Senior Notes due 2021(2)	1,130,938		1,178,598		1,230,813		1,178,922
8.125% Senior Notes due 2022	735,000		750,000		795,000		750,000
7.5% Senior Notes due 2023(3)	781,688		821,471		837,375		821,249

____________________


(1)	Carrying value is net of $4,768 and $5,264 discount at September 30, 2014 and December 31, 2013, respectively.


(2)	Carrying value includes a premium, applicable to notes issued in August 2012, of $3,598 and $3,922 at September 30, 2014 and December 31, 2013, respectively.


(3)	Carrying value is net of $3,529 and $3,751 discount at September 30, 2014 and December 31, 2013, respectively.

See Note 9 for discussion of the Company’s long-term debt.

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6. Property, Plant and Equipment

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



	September 30, 2014			December 31, 2013
Oil and natural gas properties
Proved(1)	$	11,252,074		$	10,972,816
Unproved	300,224			531,606
Total oil and natural gas properties	11,552,298			11,504,422
Less accumulated depreciation, depletion and impairment	(6,250,457		)	(5,762,969		)
Net oil and natural gas properties capitalized costs	5,301,841			5,741,453
Land	16,300			18,423
Non-oil and natural gas equipment(2)	631,781			600,603
Buildings and structures(3)	255,469			233,405
Total	903,550			852,431
Less accumulated depreciation and amortization	(324,686		)	(286,209		)
Other property, plant and equipment, net	578,864			566,222
Total property, plant and equipment, net	$	5,880,705		$	6,307,675

____________________


(1)	Includes cumulative capitalized interest of approximately $33.9 million and $23.4 million at September 30, 2014 and December 31, 2013, respectively.


(2)	Includes cumulative capitalized interest of approximately $4.3 million at both September 30, 2014 and December 31, 2013.


(3)	Includes cumulative capitalized interest of approximately $15.8 million and $12.0 million at September 30, 2014 and December 31, 2013, respectively.

Accumulated depreciation, depletion and impairment on oil and natural gas properties includes cumulative full cost ceiling limitation impairment of $3.7 billion and $3.5 billion at September 30, 2014 and December 31, 2013, respectively. During the nine-month period ended September 30, 2014, the Company reduced the net carrying value of its oil and natural gas properties by $164.8 million as a result of its first quarter full cost ceiling analysis.

Century Plant Construction Costs

Included in proved oil and natural gas properties is approximately $180.0 million of costs in excess of contracted and reimbursed amounts incurred by the Company during construction of the Century Plant in Pecos County, Texas pursuant to an agreement with Occidental. Due to the high-CO₂content of the Company’s reserves in the Piñon Field and the absence of adequate processing capacity in the Piñon Field area, construction of a large-scale processing facility, such as the Century Plant, was necessary for the development of the Company’s natural gas reserves in that area. The Company entered into the construction agreement and a related treating agreement with Occidental solely to facilitate the development of its reserves in the Piñon Field and greater West Texas Overthrust area and, accordingly, has recorded these unreimbursed costs as development costs within its full cost pool. See Note 12 for discussion of the related treating agreement.

Drilling Carry Commitments

The Company has agreements with two co-working interest parties, which contain carry commitments to fund a portion of its future drilling, completing and equipping costs within areas of mutual interest. The Company recorded approximately $205.6 million for Repsol E&P USA, Inc.’s (“Repsol”) carry during the nine-month period ended September 30, 2014, and a combined $334.2 million for both Atinum MidCon I, LLC’s (“Atinum”) and Repsol’s drilling carries during the nine-month periods ended September 30, 2013, which reduced the Company’s capital expenditures for the respective periods. Atinum fully funded its carry commitment in the third quarter of 2013, and the carry commitment from Repsol was fully utilized during the third quarter of 2014.

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Under the agreement with Repsol, 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, completing and equipping costs for subsequent wells drilled in the area of mutual interest, up to a maximum of $75.0 million in carry costs. As of September 30, 2014, the Company has drilled 241 net wells under this arrangement and currently anticipates satisfying its drilling commitment within the required time period. The Company has no other drilling obligation to Repsol.

7. Other Assets

Other assets consist of the following (in thousands):



	September 30, 2014		December 31, 2013
Debt issuance costs, net of amortization	$	54,878	$	61,923
Investments	10,389		13,708
Deferred tax asset	7,985		—
Restricted deposits(1)	—		27,955
Notes receivable on asset retirement obligations(1)	—		11,640
Other	3,816		5,945
Total other assets	$	77,068	$	121,171

____________________


(1)	Assets at December 31, 2013 were included in the sale of the Gulf Properties in February 2014, as discussed in Note 3.

8. Construction Contract

In the second quarter of 2013, the Company substantially completed the construction of a series of electrical transmission expansion and upgrade projects in northern Oklahoma for a third party. The Company constructed these projects for a contract price of $23.3 million, which included agreed upon change orders. Upon substantial completion of the contract, the Company recognized construction contract revenue and costs equal to the revised contract price of $23.3 million, which are included in the accompanying unaudited condensed consolidated statements of operations for the nine-month period ended September 30, 2013.

9. Long-Term Debt

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



	September 30, 2014		December 31, 2013
Senior credit facility	$	—	$	—
Senior notes
8.75% Senior Notes due 2020, net of $4,768 and $5,264 discount, respectively	445,232		444,736
7.5% Senior Notes due 2021, including premium of $3,598 and $3,922, respectively	1,178,598		1,178,922
8.125% Senior Notes due 2022	750,000		750,000
7.5% Senior Notes due 2023, net of $3,529 and $3,751 discount, respectively	821,471		821,249
Total debt	3,195,301		3,194,907
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,195,301	$	3,194,907

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Senior Credit Facility

The senior secured revolving credit facility (the “senior credit facility”), which was amended and restated on October 22, 2014, is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. As of September 30, 2014, the senior credit facility contained financial covenants, including maintenance of agreed upon levels for the (i) ratio of total funded net debt to EBITDA, which may not exceed 4.5:1.0 at each quarter end, calculated using the last four completed fiscal quarters and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. If no amounts are drawn under the senior credit facility when calculating the ratio of total funded 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. 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 and nine-month periods ended September 30, 2014, 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 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 is determined by reference to (a) the London Interbank Offered Rate (“LIBOR”) plus an applicable margin between 1.50% and 2.50% 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 0.50% and 1.50% 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 borrowing base or the committed amount. In October 2014, in connection with the amendment and restatement of the senior credit facility, the Company’s borrowing base was increased to $1.2 billion (previously $775.0 million). Under the amended and restated agreement, the availability of the borrowing base initially will be limited to a facility amount of $900.0 million. Upon delivery by the Company of a written request and the payment of additional up-front fees to the lenders, the facility amount may be increased up to the full borrowing base. The next redetermination is expected to take place in April 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.

At September 30, 2014, the Company had no amount outstanding under the senior credit facility and $10.4 million in outstanding letters of credit, which reduce the availability under the senior credit facility on a dollar-for-dollar basis.

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On November 14, 2014, the Company and its lenders amended the credit agreement to waive certain defaults that may have arisen as a result of the application of any new accounting treatment to the under delivery penalty described in Note 2 and extend the period for delivering the unaudited condensed consolidated financial statements for the period ended September 30, 2014.

Senior Notes

The Company’s unsecured senior fixed rate notes (“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 19 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 of the Senior Notes outstanding at September 30, 2014 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.

2013 Activity. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premium paid to redeem these notes and the expense incurred to write off the remaining associated unamortized debt issuance costs, totaling $82.0 million, were recorded as a loss on extinguishment of debt in the accompanying unaudited condensed consolidated statement of operations for the nine-month period ended September 30, 2013.

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 and nine-month periods ended September 30, 2014, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Notes.

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10. 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 loss on derivative contracts for commodity derivative contracts and in interest expense for interest rate swaps 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 September 30, 2014, the Company’s commodity derivative contracts consisted of fixed price 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.

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.

Interest Rate Swaps. The Company is exposed to interest rate risk on its long-term fixed rate debt and will be exposed to variable interest rates if it draws on its 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.

Prior to its maturity on April 1, 2013, the Company had a $350.0 million notional interest rate swap agreement which effectively fixed the variable interest rate on the Senior Floating Rate Notes due 2014 (“Senior Floating Rate Notes”) at an annual rate of 6.69% for periods prior to their repurchase and redemption in the third quarter of 2012. The interest rate swap was not designated as a hedge.

Derivatives Agreements with Royalty Trusts. The Company is party to derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II, respectively, that 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, March 31, 2015 and December 31, 2014 for the Mississippian Trust I, Permian Trust and Mississippian Trust II, respectively. 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 has 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 receive payment directly from the counterparty and pay 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. Under the derivatives agreements, as additional development wells are drilled for the benefit of the Permian Trust and the

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Mississippian Trust II, the Company has the right, under certain circumstances, to assign or novate additional derivative contracts to the Permian Trust and the Mississippian Trust II.

All contracts underlying the derivatives agreements with the Royalty Trusts, including those novated to the Permian Trust and the Mississippian Trust II, have been included in the Company’s consolidated derivative disclosures. See Note 4 for the Royalty Trusts’ open derivative contracts.

Fair Value of Derivatives. The following table presents the fair value of the Company’s derivative contracts as of September 30, 2014 and December 31, 2013 on a gross basis without regard to same-counterparty netting (in thousands):



Type of Contract	Balance Sheet Classification	September 30, 2014		December 31, 2013
Derivative assets
Oil price swaps	Derivative contracts-current	$	29,676	$	15,887
Natural gas price swaps	Derivative contracts-current	8,178		1,598
Oil collars - three way	Derivative contracts-current	15,768		706
Natural gas collars	Derivative contracts-current	297		177
Oil price swaps	Derivative contracts-noncurrent	7,405		19,376
Natural gas price swaps	Derivative contracts-noncurrent	311		—
Oil collars - three way	Derivative contracts-noncurrent	8,072		12,189
Natural gas collars	Derivative contracts-noncurrent	103		341
Derivative liabilities
Oil price swaps	Derivative contracts-current	—		(38,396		)
Natural gas price swaps	Derivative contracts-current	—		(1,460		)
Oil price swaps	Derivative contracts-noncurrent	—		(38,344		)
Total net derivative contracts		$	69,810	$	(27,926	)

See Note 5 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 September 30, 2014, the counterparties to the Company’s open derivative contracts consisted of 9 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 royalty interests (for the Permian Trust’s and the Mississippian Trust II’s novated derivative contracts) (in thousands):

September 30, 2014



	Gross Amounts		Gross Amounts Offset		Amounts Net of Offset		Financial Collateral		Net Amount
Assets
Derivative contracts - current	$	53,919	$	—	$	53,919	$	—	$	53,919
Derivative contracts - noncurrent	15,891		—		15,891		—		15,891
Total	$	69,810	$	—	$	69,810	$	—	$	69,810

Liabilities
Derivative contracts - current	$	—	$	—	$	—	$	—	$	—
Derivative contracts - noncurrent	—		—		—		—		—
Total	$	—	$	—	$	—	$	—	$	—

December 31, 2013



	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	18,368	$	(5,589	)	$	12,779	$	—		$	12,779
Derivative contracts - noncurrent	31,906		(17,780		)	14,126		—			14,126
Total	$	50,274	$	(23,369	)	$	26,905	$	—		$	26,905

Liabilities
Derivative contracts - current	$	39,856	$	(5,589	)	$	34,267	$	(34,267	)	$	—
Derivative contracts - noncurrent	38,344		(17,780		)	20,564		(20,564		)	—
Total	$	78,200	$	(23,369	)	$	54,831	$	(54,831	)	$	—

The Company recorded a (gain) loss on commodity derivative contracts of $(132.6) million and $132.8 million for the three-month periods ended September 30, 2014 and 2013, respectively, as reflected in the accompanying unaudited condensed consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(3.4) million and $12.5 million, respectively. The Company recorded a (gain) loss on commodity derivative contracts of $(4.8) million and $70.1 million for the nine-month periods ended September 30, 2014, and 2013, respectively, which includes net cash payments upon settlement of $92.9 million and $12.8 million, respectively. Included in these net cash payments are $69.6 million and $29.3 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 and the Permian Properties in February 2013, respectively.

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At September 30, 2014, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps



	Notional (MBbls)	Weighted Average Fixed Price
October 2014 - December 2014	1,115	$	98.78
January 2015 - December 2015	5,588	$	92.44
January 2016 - December 2016	1,464	$	88.36

Natural Gas Price Swaps

Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
October 2014 - December 2014	2,070	$70.00	$90.20	$100.00
January 2015 - December 2015	4,576	$76.56	$90.28	$103.48
January 2016 - December 2016	2,556	$83.13	$90.00	$100.85

Natural Gas Collars



	Notional (MMcf)	Collar Range
October 2014 - December 2014	236	$4.00	—	$7.78
January 2015 - December 2015	1,010	$4.00	—	$8.55

11. Asset Retirement Obligations

A reconciliation of the beginning and ending aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2013 to September 30, 2014 is as follows (in thousands):



Asset retirement obligations at December 31, 2013	$	424,117
Liability incurred upon acquiring and drilling wells	3,835
Revisions in estimated cash flows	(438		)
Liability settled or disposed in current period(1)	(377,745		)
Accretion	7,927
Asset retirement obligations at September 30, 2014	57,696
Less: current portion	—
Asset retirement obligations, net of current	$	57,696

____________________

(1) Includes $366.0 million associated with the Gulf Properties sold in February 2014.

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12. 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. It is anticipated that the plaintiffs will seek rehearing by the Court of Appeals and possibly petition 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. 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.

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

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


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


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


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


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


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

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.

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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.

Because the Federal Shareholder Derivative Litigation and the State Shareholder Derivative Litigation are in the early stages, an estimate of reasonably possible losses associated with each of them, 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 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 fifteen 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.

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.

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 gas rights. The Company is cooperating with the investigation.

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

In addition to the 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, 2013, the Company had delivered to Occidental 34.0 Bcf of CO2, which is 164.4 Bcf less than the cumulative minimum annual CO2 volume requirements for the same period. 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 $115.1 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.

Under certain circumstances, the Company will have the right, beginning in 2020, to reduce future minimum annual

CO2 volume requirements under the agreement by paying Occidental an amount equal to the present value of $0.70 multiplied by such reduced CO2 volume requirements as designated by the Company. As of September 30, 2014, if the Company were to cease delivering natural gas for processing and made no future CO2 deliveries from such date until 2020, the estimated amount required to be paid in 2020 in order to adjust the future CO₂ volume requirements to zero, including applicable annual delivery shortfall penalties, would be approximately $585.7 million. 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.

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Based upon the quantity of CO2 delivered by the Company during the period from January 1, 2014 through September 30, 2014 and the estimated quantities the Company expects to deliver during the remainder of 2014 the Company accrued estimated annual under delivery penalties ($0.25 per Mcf) of approximately $8.6 million and $25.3 million for the three and nine-month periods ended September 30, 2014, respectively. Additionally, the Company has included an accrued expense for the three and nine-month periods ended September 30, 2013 of $8.3 million and $24.3 million, respectively. for the $0.25 Mcf fee attributable to the estimated 2013 annual under delivery penalty based upon the quantity of CO₂ delivered by the Company during the period from January 1, 2013 through September 30, 2013 as described in Note 2. Based on current projected natural gas production levels, the Company expects to accrue between approximately $30.0 million and $37.0 million during the year ending December 31, 2014 for amounts related to the Company’s anticipated shortfall in meeting its 2014 annual delivery obligations. The Company has not accrued any liability for the $0.70 per Mcf fee (approximately $70.9 million total) that would be due in 2041 if these anticipated shortfalls occur and are not made up in the future as the Company does not currently believe such payment is probable.

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

Under the equity purchase agreement associated with the sale of the Gulf Properties, the Company has guaranteed 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. See Note 3 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. Additionally, the Company has a drilling obligation to each of the Permian Trust and the Mississippian Trust II. See Note 4 for discussion of these drilling obligations. 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, including proceeds received from the sale of the Gulf Properties, cash flows from operating activities and availability under the Company’s credit facility, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for the remainder of 2014 and 2015. However, a substantial or extended decline in oil or natural gas prices could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced, which could adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility. See Note 9 for discussion of the financial covenants in the senior credit facility.

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13. Equity

Preferred Stock Dividends

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 income available (loss applicable) to the Company’s common stockholders and the Company’s basic income (loss) per share calculation for the three and nine-month periods ended September 30, 2014 and 2013 as presented in the accompanying unaudited condensed consolidated statements of operations, are included in the tables below (in thousands):



	Three Months Ended September 30,
	2014						2013
	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		—		500		500		2,500		3,000
7.0% Convertible perpetual preferred stock	—		5,250		5,250		—		5,250		5,250
Total	$	3,315	$	8,066	$	11,381	$	3,315	$	10,566	$	13,881

	Nine Months Ended September 30,
	2014						2013
	Dividends Paid		Dividends Unpaid		Total		Dividends Paid		Dividends Unpaid		Total
8.5% Convertible perpetual preferred stock	$	14,078	$	2,816	$	16,894	$	14,078	$	2,816	$	16,894
6.0% Convertible perpetual preferred stock	6,500		—		6,500		6,500		2,500		9,000
7.0% Convertible perpetual preferred stock	7,875		7,875		15,750		7,875		7,875		15,750
Total	$	28,453	$	10,691	$	39,144	$	28,453	$	13,191	$	41,644

In December 2014, all outstanding shares of the 6.0% convertible preferred stock converted automatically into shares of the Company’s common stock at the then-prevailing conversion rate. The final dividend payment for the 6.0% convertible preferred stock was made during the three-month period ended September 30, 2014.

Treasury Stock and Stock Repurchase Program

The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The following table shows the number of shares withheld for taxes and the associated value of those shares for the nine-month periods ended September 30, 2014 and 2013. These shares were accounted for as treasury stock when withheld and then immediately retired.



	Nine Months Ended September 30,
	2014		2013
	(In thousands)
Number of shares withheld for taxes	1,004		5,604
Value of shares withheld for taxes	$	6,281	$	29,661

In September 2014, the Company’s Board of Directors approved a share repurchase program under which the Company can repurchase up to $200.0 million of the Company’s common stock. Under the program’s terms, shares may be repurchased on the open market, through privately negotiated transactions such as block trades, or by other means as determined by SandRidge’s management and in accordance with the requirements of the Securities and Exchange Commission. The timing and actual number of shares repurchased will depend on a variety of factors including price, corporate and regulatory requirements, and other conditions. There is no fixed termination date for this repurchase program, and the repurchase program may be suspended or

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discontinued at any time. Payment for shares repurchased under the program will be funded using the Company's working capital. During the three-month period ended September 30, 2014, 3,500,000 shares totaling $17.5 million were repurchased under the program at prices equivalent to the then current market price and immediately retired. As the Company had an accumulated deficit balance during the third quarter of 2014, the excess of the repurchase price over the par value was fully applied to additional paid-in capital.

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. Under the settlement agreement, the Company’s former CEO agreed to pay to the Company $5.0 million in four installments over four years commencing October 2013 and to waive his rights under his indemnification agreement with the Company with respect to the Section 16(b) action. The Company agreed to pay the fees of the plaintiff’s lawyers and paid the former CEO’s legal expenses as required under his indemnification agreement.

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 amount receivable under the agreement as of September 30, 2014 and December 31, 2013 was $3.8 million.

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 and nine-month periods ended September 30, 2014, the Company recognized equity compensation expense of $5.1 million and $18.6 million, net of $1.5 million and $4.5 million capitalized, respectively, related to restricted common stock. For the three and nine-month periods ended September 30, 2013, the Company recognized equity compensation expense of $6.8 million and $77.5 million, net of $1.3 million and $4.3 million capitalized, respectively, related to restricted common stock. The nine-month period ended September 30, 2013 includes approximately $48.5 million of equity compensation expense recognized in connection with the separation of certain former executives from the Company.

See Note 17 for discussion of the Company’s performance units.

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14. 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 (benefit) provision for income taxes consisted of the following components for the three and nine-month periods ended September 30, 2014 and 2013 (in thousands):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014			2013
Current
Federal	$	(1,160	)	$	687	$	(1,160	)	$	4,702
State	96			1,676		(971		)	2,598
	(1,064		)	2,363		(2,131		)	7,300
Deferred
Federal	—			—		—			—
State	—			—		—			—
	—			—		—			—
Total (benefit) provision	(1,064		)	2,363		(2,131		)	7,300
Less: income tax provision attributable to noncontrolling interest	66			96		236			242
Total (benefit) provision attributable to SandRidge Energy, Inc.	$	(1,130	)	$	2,267	$	(2,367	)	$	7,058

Deferred income taxes are provided to reflect the future tax consequences of temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements. The Company’s deferred tax assets have been reduced by a valuation allowance due to a determination that it is more likely than not that some or all of the deferred assets will not be realized based on the weight of all available evidence. The Company continues to closely monitor and weigh all available evidence, including both positive and negative, in making its determination whether to maintain a valuation allowance. As a result of the significant weight placed on the Company's cumulative negative earnings position, the Company continued to maintain the full valuation allowance against its net deferred tax asset at September 30, 2014.

Internal Revenue Code (“IRC”) Section 382 addresses company ownership changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change. The Company experienced ownership changes within the meaning of IRC Section 382 during 2008 and 2010 that subjected certain of the Company’s tax attributes, including $929.4 million of federal net operating loss carryforwards, to the IRC Section 382 limitation. These limitations could result in a material amount of existing loss carryforwards expiring unused. None of these limitations resulted in a current federal tax liability at September 30, 2014.

At September 30, 2014 and December 31, 2013, the Company had a liability of approximately $0.1 million and $1.4 million, respectively, for unrecognized tax benefits. Included in the $1.4 million liability for unrecognized tax benefits at December 31, 2013 was $0.1 million for interest and penalties relating to uncertain tax positions. 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 of determining the amount of remaining federal net operating loss and other carryforwards. The number of years open for state tax audits varies, depending on the state, but are generally from three to five years.

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15. Earnings (Loss) per Share

The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share, for the three and nine-month periods ended September 30, 2014 and 2013:



	Net Income (Loss)			Weighted Average Shares		Earnings (Loss) Per Share
	(In thousands, except per share amounts)
Three Months Ended September 30, 2014
Basic earnings per share	$	145,957		485,458		$	0.30
Effect of dilutive securities
Restricted stock	—			320
Convertible preferred stock	11,381			90,133
Diluted earnings per share	$	157,338		575,911		$	0.27
Three Months Ended September 30, 2013 (Restated)
Basic loss per share	$	(95,328	)	$	483,582	$	(0.20	)
Effect of dilutive securities
Restricted stock	—			—
Convertible preferred stock(2)	—			—
Diluted loss per share	$	(95,328	)	483,582		$	(0.20	)

Nine Months Ended September 30, 2014
Basic loss per share	$	(51,036	)	485,194		$	(0.11	)
Effect of dilutive securities
Restricted stock(1)	—			—
Convertible preferred stock(2)	—			—
Diluted loss per share	$	(51,036	)	485,194		$	(0.11	)
Nine Months Ended September 30, 2013 (Restated)
Basic loss per share	$	(638,895	)	480,209		$	(1.33	)
Effect of dilutive securities
Restricted stock(1)	—			—
Convertible preferred stock(2)	—			—
Diluted loss per share	$	(638,895	)	480,209		$	(1.33	)

____________________


(1)	Restricted stock awards covering 2.8 million shares and 1.0 million shares for the nine-month periods ended September 30, 2014 and 2013, respectively, were excluded from the computation of loss per share because their effect would have been antidilutive.


(2)	Potential common shares related to the Company’s outstanding 8.5%, 6.0% and 7.0% convertible perpetual preferred stock covering 90.1 million shares for the nine-month period ended September 30, 2014 and the three and nine-month periods ended September 30, 2013, were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

See Note 13 for discussion of preferred stock dividends.

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16. Related Party Transactions

Former Chairman and CEO Severance. On June 28, 2013, the Company’s then current CEO, Tom Ward, separated employment from the Company. In accordance with the terms of Mr. Ward’s employment agreement, the Company incurred $57.9 million in salary and bonus expense and $36.8 million associated with the accelerated vesting of 6.3 million shares of restricted stock awards during the nine-month period ended September 30, 2013. As of September 30, 2014, the remaining amounts due under the terms of his employment agreement include $3.5 million to be paid in monthly installments through December 2016. These amounts are included in other current liabilities and other long-term obligations in the accompanying unaudited condensed consolidated balance sheet. See Note 13 for discussion of the stockholder receivable due from Mr. Ward.

Other Employee Termination Benefits. Certain employees received termination benefits, including severance and accelerated stock vesting, upon separation of service from the Company during the nine-month periods ended September 30, 2014 and 2013. For the nine-month period ended September 30, 2014 employee termination benefits were $8.9 million primarily as a result of the sale of the Gulf Properties. For the nine-month period ended September 30, 2013, employee termination benefits, excluding amounts attributable to the Company’s former chairman and CEO, were $25.7 million primarily as a result of other executives’ separation from employment and the sale of the Permian Properties.

2014 Divestiture. See Note 3 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 4 for additional discussion.

17. Performance Units

The Company periodically grants performance units to certain members of senior management under the Company’s existing long-term incentive plan which vest over a performance period of approximately three years. The value, and ultimate payout, 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. If performance exceeds established minimum thresholds, payout percentages could range from 50% to 200% of specified target values. If minimum target thresholds are not met, the payout is reduced to zero.

The performance units are valued for accounting purposes using a Monte Carlo simulation based on certain assumptions, including (i) a volatility assumption based on the historical realized price volatility of the Company’s common stock and the common stock of the predetermined peer group for each grant year and (ii) a risk-free interest rate based on the U.S. Treasury bond yields for a term commensurate with the approximate remaining vesting period for each grant. As of September 30, 2014 and December 31, 2013, the Company’s liability associated with performance units totaled $1.8 million. The liability represents the fair value of the portion of performance units for which requisite service has been completed. The following table presents a summary of the fair value of the performance units and the related assumptions for all outstanding units as of September 30, 2014.




Expected price volatility range	21.1	%	-	54.3%
Weighted-average risk-free interest rate				0.5%
Weighted-average fair value per unit				$43.77

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18. 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(2)			Midstream Services			All Other			Consolidated Total
Three Months Ended September 30, 2014
Revenues	$	359,613		$	51,082		$	31,132		$	1,224		$	443,051
Inter-segment revenue	—			(29,734		)	(19,210		)	—			(48,944		)
Total revenues	$	359,613		$	21,348		$	11,922		$	1,224		$	394,107
Income (loss) from operations	$	275,191		$	(1,155	)	$	(3,218	)	$	(14,327	)	$	256,491
Interest expense	—			—			—			(59,783		)	(59,783		)
Other (expense) income, net	(38		)	(89		)	5			(151		)	(273		)
Income (loss) before income taxes	$	275,153		$	(1,244	)	$	(3,213	)	$	(74,261	)	$	196,435
Capital expenditures(3)	$	435,758		$	3,603		$	14,045		$	14,422		$	467,828
Depreciation, depletion, amortization, accretion and impairment	$	113,711		$	6,884		$	2,584		$	4,977		$	128,156
Three Months Ended September 30, 2013 (Restated)
Revenues	$	462,582		$	44,527		$	37,876		$	767		$	545,752
Inter-segment revenue	(79		)	(28,335		)	(23,735		)	—			(52,149		)
Total revenues	$	462,503		$	16,192		$	14,141		$	767		$	493,603
(Loss) income from operations	$	(19,858	)	$	(8,276	)	$	(7,691	)	$	33,659		$	(2,166	)
Interest income (expense)	331			—			—			(61,716		)	(61,385		)
Other (expense) income, net	(350		)	—			(41		)	1,049			658
Loss before income taxes	$	(19,877	)	$	(8,276	)	$	(7,732	)	$	(27,008	)	$	(62,893	)
Capital expenditures(3)	$	292,697		$	3,142		$	16,551		$	10,192		$	322,582
Depreciation, depletion, amortization, accretion and impairment	$	146,286		$	8,252		$	2,128		$	5,402		$	162,068
Nine Months Ended September 30, 2014
Revenues	$	1,106,883		$	150,054		$	115,846		$	3,299		$	1,376,082
Inter-segment revenue	(26		)	(92,774		)	(71,405		)	—			(164,205		)
Total revenues	$	1,106,857		$	57,280		$	44,441		$	3,299		$	1,211,877
Income (loss) from operations	$	288,497		$	(6,605	)	$	(6,973	)	$	(58,679	)	$	216,240
Interest income (expense), net	138			—			—			(183,827		)	(183,689		)
Other (expense) income, net	(272		)	(561		)	5			3,987			3,159
Income (loss) before income taxes	$	288,363		$	(7,166	)	$	(6,968	)	$	(238,519	)	$	35,710
Capital expenditures(3)	$	1,056,568		$	10,877		$	25,810		$	27,282		$	1,120,537
Depreciation, depletion, amortization, accretion and impairment	$	497,888		$	25,390		$	7,534		$	15,452		$	546,264
At September 30, 2014
Total assets	$	5,685,412		$	142,104		$	193,630		$	957,243		$	6,978,389

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	Exploration and Production(1)			Drilling and Oil Field Services(2)			Midstream Services			All Other			Consolidated Total
Nine Months Ended September 30, 2013(Restated)
Revenues	$	1,402,366		$	141,364		$	139,001		$	2,399		$	1,685,130
Inter-segment revenue	(241		)	(91,713		)	(74,896		)	—			(166,850		)
Total revenues	$	1,402,125		$	49,651		$	64,105		$	2,399		$	1,518,280
Loss from operations	$	(95,927	)	$	(36,684	)	$	(18,106	)	$	(140,545	)	$	(291,262	)
Interest income (expense), net	757			—			—			(209,211		)	(208,454		)
Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
Other income (expense), net	157			—			(914		)	1,920			1,163
Loss before income taxes	$	(95,013	)	$	(36,684	)	$	(19,020	)	$	(429,841	)	$	(580,558	)
Capital expenditures(3)	$	1,008,869		$	4,657		$	46,883		$	38,043		$	1,098,452
Depreciation, depletion, amortization, accretion and impairment	$	462,683		$	36,544		$	7,832		$	18,018		$	525,077
At December 31, 2013
Total assets	$	6,157,225		$	158,737		$	188,165		$	1,180,668		$	7,684,795

____________________


(1)	Income (loss) from operations includes a full cost ceiling limitation impairment of $164.8 million for the nine-month period ended September 30, 2014, and a loss on the sale of the Permian Properties of $398.9 million for the nine-month period ended September 30, 2013.


(2)	Income (loss) from operations includes an impairment of $3.1 million and $11.1 million on certain drilling assets held for sale for the nine-month periods ended September 30, 2014 and September 30, 2013, respectively.


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

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19. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. As of September 30, 2014, 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 3, guaranteed the Company’s registered debt. Upon the closing of the sale, these subsidiaries were released from their guarantees. The condensed consolidating financial information in the tables below reflects these subsidiaries’ financial information through the date of the sale.

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

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Condensed Consolidating Balance Sheets



	September 30, 2014
	Parent		Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	580,697	$	1,796	$	7,753	$	—		$	590,246
Accounts receivable, net	2,372		311,667		18,876		(2,372		)	330,543
Intercompany accounts receivable	480,898		1,341,756		51,433		(1,874,087		)	—
Derivative contracts	—		47,929		15,835		(9,845		)	53,919
Prepaid expenses	—		6,782		12		—			6,794
Other current assets	—		23,206		17		—			23,223
Total current assets	1,063,967		1,733,136		93,926		(1,886,304		)	1,004,725
Property, plant and equipment, net	—		4,790,902		1,089,803		—			5,880,705
Investment in subsidiaries	6,245,116		21,021		—		(6,266,137		)	—
Derivative contracts	—		15,891		1,980		(1,980		)	15,891
Other assets	62,863		19,403		704		(5,902		)	77,068
Total assets	$	7,371,946	$	6,580,353	$	1,186,413	$	(8,160,323	)	$	6,978,389
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	163,774	$	486,207	$	5,040	$	(2,372	)	$	652,649
Intercompany accounts payable	1,335,071		503,580		35,436		(1,874,087		)	—
Derivative contracts	—		9,845		—		(9,845		)	—
Other current liabilities	7,985		10,564		—		—			18,549
Total current liabilities	1,506,830		1,010,196		40,476		(1,886,304		)	671,198
Investment in subsidiaries	892,524		141,566		—		(1,034,090		)	—
Long-term debt	3,201,203		—		—		(5,902		)	3,195,301
Derivative contracts	—		1,980		—		(1,980		)	—
Asset retirement obligations	—		57,696		—		—			57,696
Other long-term obligations	95		16,323		—		—			16,418
Total liabilities	5,600,652		1,227,761		40,476		(2,928,276		)	3,940,613
Equity
SandRidge Energy, Inc. stockholders’ equity	1,771,294		5,352,592		1,145,937		(6,498,529		)	1,771,294
Noncontrolling interest	—		—		—		1,266,482			1,266,482
Total equity	1,771,294		5,352,592		1,145,937		(5,232,047		)	3,037,776
Total liabilities and equity	$	7,371,946	$	6,580,353	$	1,186,413	$	(8,160,323	)	$	6,978,389

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	December 31, 2013 (Revised)
	Parent(1)		Guarantors(2)		Non-Guarantors		Eliminations(1)(2)			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	805,505	$	1,013	$	8,145	$	—		$	814,663
Accounts receivable, net	—		326,345		22,873		—			349,218
Intercompany accounts receivable	153,325		982,524		70,107		(1,205,956		)	—
Derivative contracts	—		7,796		14,748		(9,765		)	12,779
Prepaid expenses	—		39,165		88		—			39,253
Other current assets	1,376		24,410		124		—			25,910
Total current assets	960,206		1,381,253		116,085		(1,215,721		)	1,241,823
Property, plant and equipment, net	—		5,125,543		1,182,132		—			6,307,675
Investment in subsidiaries	6,009,603		49,418		—		(6,059,021		)	—
Derivative contracts	—		12,650		9,585		(8,109		)	14,126
Other assets	61,923		65,123		27		(5,902		)	121,171
Total assets	$	7,031,732	$	6,633,987	$	1,307,829	$	(7,288,753	)	$	7,684,795
LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	207,572	$	601,074	$	3,842	$	—		$	812,488
Intercompany accounts payable	967,365		181,573		57,018		(1,205,956		)	—
Derivative contracts	—		44,032		—		(9,765		)	34,267
Asset retirement obligations	—		87,063		—		—			87,063
Total current liabilities	1,174,937		913,742		60,860		(1,215,721		)	933,818
Investment in subsidiaries	828,794		152,266		—		(981,060		)	—
Long-term debt	3,200,809		—		—		(5,902		)	3,194,907
Derivative contracts	—		28,673		—		(8,109		)	20,564
Asset retirement obligations	—		337,054		—		—			337,054
Other long-term obligations	1,382		21,443		—		—			22,825
Total liabilities	5,205,922		1,453,178		60,860		(2,210,792		)	4,509,168
Equity
SandRidge Energy, Inc. stockholders’ equity	1,825,810		5,180,809		1,246,969		(6,427,778		)	1,825,810
Noncontrolling interest	—		—		—		1,349,817			1,349,817
Total equity	1,825,810		5,180,809		1,246,969		(5,077,961		)	3,175,627
Total liabilities and equity	$	7,031,732	$	6,633,987	$	1,307,829	$	(7,288,753	)	$	7,684,795

____________________

(1)

Amounts presented as Investment in subsidiaries have been revised to present negative investments in certain subsidiaries, totaling $828.8 million, as liabilities and to present $55.6 million Parent gain on sale of subsidiary with full cost pool assets in 2012 as a reduction to Guarantor full cost pool (property, plant and equipment, net) and a reduction to Parent equity. Gain on sale of subsidiary was previously classified as an adjustment to the consolidated full cost pool through elimination in the condensed consolidating balance sheets. The impact of these revisions was not material to any previously issued financial statements.

(2)

Amounts presented as Investment in subsidiaries have been revised to present negative investments in certain subsidiaries, totaling $152.3 million, as liabilities. Property, plant and equipment, net has been revised to present $55.6 million Parent gain on sale of subsidiary with full cost pool assets in 2012 as a reduction to the Guarantor full cost pool (property, plant and equipment, net) and a reduction to Guarantor equity. Gain on sale of subsidiary was previously classified as an adjustment to the consolidated full cost pool through elimination in the condensed consolidating balance sheets. The impact of these revisions was not material to any previously issued financial statements.

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Condensed Consolidating Statements of Operations



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

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	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Three Months Ended September 30, 2013 (Restated)
Total revenues	$	—		$	411,847		$	81,830		$	(74	)	$	493,603
Expenses
Direct operating expenses(1)	—			154,175			6,283			(74		)	160,384
General and administrative	83			38,894			993			—			39,970
Depreciation, depletion, amortization and accretion	—			140,350			21,031			—			161,381
Impairment	—			515			172			—			687
Loss on derivative contracts	—			103,215			29,593			—			132,808
Loss (gain) on sale of assets	—			900			(361		)	—			539
Total expenses(1)	83			438,049			57,711			(74		)	495,769
(Loss) income from operations(1)	(83		)	(26,202		)	24,119			—			(2,166		)
Equity earnings from subsidiaries	(17,420		)	7,803			—			9,617			—
Interest (expense) income	(61,716		)	331			—			—			(61,385		)
Other income, net	—			648			10			—			658
(Loss) income before income taxes(1)	(79,219		)	(17,420		)	24,129			9,617			(62,893		)
Income tax expense	2,228			—			135			—			2,363
Net (loss) income(1)	(81,447		)	(17,420		)	23,994			9,617			(65,256		)
Less: net income attributable to noncontrolling interest	—			—			—			16,191			16,191
Net (loss) income attributable to SandRidge Energy, Inc.(1)	$	(81,447	)	$	(17,420	)	$	23,994		$	(6,574	)	$	(81,447	)

____________________


(1)	Guarantor and Consolidated direct operating expenses have been restated to reflect accrual of the CO₂ delivery shortfall penalty. See Note 2.

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

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	Parent			Guarantors			Non-Guarantors				Eliminations				Consolidated
	(In thousands)
Nine Months Ended September 30, 2013 (Restated)
Total revenues	$	—		$	1,277,289		$	241,314			$	(323	)		$	1,518,280
Expenses
Direct operating expenses(1)	—			499,027			24,671				(323		)		523,375
General and administrative	258			287,365			5,052				—				292,675
Depreciation, depletion, amortization and accretion	—			441,538			67,209				—				508,747
Impairment	—			13,218			3,112				—				16,330
Loss on derivative contracts	—			45,462			24,589				—				70,051
Loss on sale of assets	—			291,516			106,848				—				398,364
Total expenses(1)	258			1,578,126			231,481			—	(323		)	—	1,809,542
(Loss) income from operations(1)	(258		)	(300,837		)	9,833				—				(291,262		)
Equity earnings from subsidiaries	(298,822		)	(606		)	—				299,428				—
Interest (expense) income	(209,211		)	757			—				—				(208,454		)
Loss on extinguishment of debt	(82,005		)	—			—				—				(82,005		)
Other income (expense), net	—			1,864			(701		)		—				1,163
(Loss) income before income taxes(1)	(590,296		)	(298,822		)	9,132				299,428				(580,558		)
Income tax expense	6,955			—			345				—				7,300
Net (loss) income(1)	(597,251		)	(298,822		)	8,787				299,428				(587,858		)
Less: net income attributable to noncontrolling interest	—			—			—				9,393				9,393
Net (loss) income attributable to SandRidge Energy, Inc.(1)	$	(597,251	)	$	(298,822	)	$	8,787			$	290,035			$	(597,251	)

____________________


(1)	Guarantor and Consolidated direct operating expenses have been restated to reflect accrual of the CO₂ delivery shortfall penalty. See Note 2.

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Condensed Consolidating Statements of Cash Flows



	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2014
Net cash provided by operating activities	$	173,597		$	49,777		$	178,603		$	(6,293	)	$	395,684
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(1,071,465		)	—			—			(1,071,465		)
Proceeds from sale of assets	—			711,547			2,747			—			714,294
Other	—			(146,274		)	1,061			128,293			(16,920		)
Net cash (used in) provided by investing activities	—			(506,192		)	3,808			128,293			(374,091		)
Cash flows from financing activities
Distributions to unitholders	—			—			(184,176		)	33,736			(150,440		)
Intercompany (advances) borrowings, net	(327,573		)	327,459			114			—			—
Other	(70,832		)	129,739			1,259			(155,736		)	(95,570		)
Net cash (used in) provided by financing activities	(398,405		)	457,198			(182,803		)	(122,000		)	(246,010		)
Net (decrease) increase in cash and cash equivalents	(224,808		)	783			(392		)	—			(224,417		)
Cash and cash equivalents at beginning of year	805,505			1,013			8,145			—			814,663
Cash and cash equivalents at end of period	$	580,697		$	1,796		$	7,753		$	—		$	590,246

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	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Nine Months Ended September 30, 2013
Net cash (used in) provided by operating activities	$	(157,030	)	$	539,973		$	211,364		$	700		$	595,007
Cash flows from investing activities
Capital expenditures for property, plant, and equipment	—			(1,163,539		)	—			—			(1,163,539		)
Proceeds from sale of assets	—			2,566,900			455			—			2,567,355
Other	—			18,756			37			(34,320		)	(15,527		)
Net cash provided by investing activities	—			1,422,117			492			(34,320		)	1,388,289
Cash flows from financing activities
Repayments of borrowings	(1,115,500		)	—			—			—			(1,115,500		)
Distribution to unitholders	—			—			(226,404		)	73,402			(153,002		)
Premium on debt redemption	(61,997		)	—			—			—			(61,997		)
Intercompany borrowings (advances), net	2,021,132			(2,025,243		)	4,111			—			—
Other	(76,390		)	63,069			10,797			(39,782		)	(42,306		)
Net cash provided by (used in) financing activities	767,245			(1,962,174		)	(211,496		)	33,620			(1,372,805		)
Net increase (decrease) in cash and cash equivalents	610,215			(84		)	360			—			610,491
Cash and cash equivalents at beginning of year	300,228			922			8,616			—			309,766
Cash and cash equivalents at end of period	$	910,443		$	838		$	8,976		$	—		$	920,257

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20. Subsequent Events

Royalty Trust Distributions. On October 30, 2014, the Royalty Trusts announced quarterly distributions for the three-month period ended September 30, 2014. The following distributions were paid on November 28, 2014 to holders of record as of the close of business on November 14, 2014 (in thousands):



Royalty Trust	Total Distribution		Amount Distributed to Third-Party Unitholders
Mississippian Trust I	$	6,913	$	5,055
Permian Trust	28,245		25,830
Mississippian Trust II	14,992		12,482
Total	$	50,150	$	43,367

Repurchases of Common Stock. During October 2014, the Company repurchased 23,911,000 shares of its common stock for approximately $93.8 million, excluding fees of $0.5 million, in open market transactions pursuant to the share repurchase program approved by the Company’s Board of Directors and announced in September 2014. As of December 31, 2014, approximately $88.7 million may yet be repurchased under the share repurchase program.

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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 2013 Form 10-K/A. The Company’s discussion and analysis includes the following subjects:


•	Overview;


•	Results by Segment;


•	Consolidated Results of Operations;


•	Liquidity and Capital Resources;


•	Critical Accounting Policies and Estimates; and


•	Valuation Allowance.

The financial information with respect to the three and nine-month periods ended September 30, 2014 and 2013, 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.

Restatement of Prior Period Financial Information. As described further in Note 2 to the accompanying unaudited condensed consolidated financial statements, the Company has restated its unaudited condensed consolidated financial statements and related disclosures for the three and nine-month periods ended September 30, 2013. The following discussion and analysis of the Company’s financial condition and results of operations incorporates the restated amounts. For this reason, the data set forth in this Item 2 may not be comparable to the discussion and data in the Company’s previously filed quarterly reports on Form 10-Q for the three and nine-month periods ended September 30, 2013.

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 owns and operates additional interests in west Texas and owned interests in the Gulf of Mexico and Gulf Coast until February 2014, as discussed under “2014 Developments and Outlook” below. 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 system, an electrical transmission system and a drilling and related oil field services business.

SandRidge’s mission is to be a high-return, growth-oriented resource conversion company focused in the Mid-Continent region of the United States. During the Company’s 2013 capital allocation process, management identified competitive advantages, such as its industry leading cost structure, subsurface knowledge, existing infrastructure and broader infrastructure capabilities and size and scale, all in the Mid-Continent area. As a result of that process, the decision was made to enhance the Company’s focus in the Mid-Continent, divest the Gulf Properties, and redeploy capital into onshore areas where the Company has a more extensive opportunity set and over a ten-year inventory of high-return drilling locations.

Operational Highlights

Operational highlights for the three and nine-month periods ended September 30, 2014 include the following:

•

Drilled 116 and 328 wells, excluding salt water disposal wells, in the Mid-Continent area during the three and nine-month periods ended September 30, 2014, respectively. Mid-Continent properties contributed approximately 6.3 MMBoe or 85.8% and 16.3 MMBoe or 78.2% of the Company’s total production, for the three and nine-month periods ended September 30, 2014, respectively, compared to approximately 4.6 MMBoe or 55.7% and 12.9 MMBoe, or 50.3% for the three and nine-month periods ended September 30, 2013, respectively.


•	Gulf of Mexico properties contributed production of approximately 1.3 MMBoe, or 6.3%, of the Company’s total production, for the nine-month period ended September 30, 2014 compared to approximately 8.0 MMBoe, or 31.1% of total production, for the nine-month period ended September 30, 2013.

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•

Total production for the three-month period ended September 30, 2014 was comprised of approximately 36.0% oil, 48.9% natural gas and 15.1% NGLs compared to 40.9% oil, 52.1% natural gas and 7.0% NGLs in the same period of 2013. Total production for the nine-month period ended September 30, 2014 was comprised of approximately 38.1% oil, 49.9% natural gas and 12.0% NGLs compared to 42.6% oil, 51.1% natural gas and 6.3% NGLs in the same period of 2013.

2013 Transactions

Sale of Permian Properties. On February 26, 2013, the Company sold the Permian Properties for $2.6 billion. The Company used a portion of the sale proceeds to fund the redemption of approximately $1.1 billion aggregate principal amount of outstanding Senior Notes, discussed below, and used the remaining proceeds to fund its capital expenditures in the Mid-Continent and for general corporate purposes. The Company recorded a non-cash loss on the sale of $398.9 million during the nine-month period ended September 30, 2013, of which $71.7 million was allocated to noncontrolling interests. Additionally, the Company settled a portion of its existing oil derivative contracts in February 2013 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 $29.6 million.

Production, revenues and direct operating expenses of the Permian Properties included in the Company’s results for the nine-month period ended September 30, 2013 were as follows:



	Nine Months Ended September 30, 2013(1)
Production (MBoe)	1,148
Revenues (in thousands)	$	68,027
Direct operating expenses (in thousands)	$	17,453

_______________

(1) Includes activity through February 26, 2013, the date of sale.

Redemption of Senior Notes. In March 2013, the Company redeemed the outstanding $365.5 million aggregate principal amount of its 9.875% Senior Notes due 2016 and the outstanding $750.0 million aggregate principal amount of its 8.0% Senior Notes due 2018 for total consideration of $1,061.34 per $1,000 principal amount and $1,052.77 per $1,000 principal amount, respectively. The premium paid to redeem these notes and the expense incurred to write off the remaining associated unamortized debt issuance costs resulted in a loss on extinguishment of debt of $82.0 million for the nine-month period ended September 30, 2013.

2014 Transactions

Sale of Gulf of Mexico and Gulf Coast Properties. 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 is using the proceeds from the sale to fund its drilling in the Mid-Continent. 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. Without regard to same-counterparty netting, these derivative contracts were in a liability position at December 31, 2013 of $72.4 million.

Production, revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties included in the Company’s results for the three-month period ended September 30, 2013 and the nine-month periods ended September 30, 2014 and 2013 were as follows:



	Three Months Ended September 30,		Nine Months Ended September 30,
	2013		2014(1)		2013
Production (MBoe)	2,429		1,321		7,961
Revenues (in thousands)	$	153,315	$	90,920	$	498,590
Expenses (in thousands)	$	126,137	$	63,674	$	377,529

_______________

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

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Outlook

In 2014, the Company is focused on the execution of its highest return projects, enhanced capital discipline and the utilization of its identified competitive advantages. The Company’s 2014 capital expenditures budget is approximately $1.5 billion, with approximately $1.4 billion designated for exploration and production activities.

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Results by Segment

The Company operates in three 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 and nine-month periods ended September 30, 2014 and 2013 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 commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. To provide information on the general trend in pricing, the average NYMEX prices for oil and natural gas during the three and nine-month periods ended September 30, 2014 and 2013 are shown in the following table:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Oil (per Bbl)	$	97.25	$	105.81	$	99.62	$	98.20
Natural gas (per Mcf)	$	3.95	$	3.56	$	4.41	$	3.69

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 mitigates the risk that it will not have adequate funds available for its capital expenditure programs.

Saltwater Gathering System. Included within the Company’s full cost pool is a produced water disposal system that included over 900 miles of gathering lines and 186 active disposal wells at September 30, 2014. 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 2.5 million barrels of water per day.

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Set forth in the table below is financial, production and pricing information for the exploration and production segment for the three and nine-month periods ended September 30, 2014 and 2013.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013 (Restated)			2014			2013 (Restated)
Results (in thousands)
Revenues
Oil	$	250,121		$	356,986		$	769,907		$	1,072,652
NGL	39,780			20,974			94,602			55,455
Natural gas	69,712			81,251			240,326			263,403
Other	—			3,371			2,048			10,856
Inter-segment revenue	—			(79		)	(26		)	(241		)
Total revenues	359,613			462,503			1,106,857			1,402,125
Operating expenses
Production	83,211			125,312			258,228			392,363
Production taxes	8,380			8,816			24,027			24,819
Depreciation and depletion—oil and natural gas	112,569			137,639			325,021			434,068
Accretion of asset retirement obligations	1,116			8,472			7,927			28,051
Impairment	—			—			164,779			—
(Gain) loss on derivative contracts	(132,575		)	132,808			(4,792		)	70,051
(Gain) loss on sale of assets	(11		)	(506		)	(33		)	398,543
Other operating expenses	11,732			69,820			43,203			150,157
Total operating expenses	84,422			482,361			818,360			1,498,052
Income (loss) from operations	$	275,191		$	(19,858	)	$	288,497		$	(95,927	)

Production data
Oil (MBbls)	2,644			3,372			7,927			10,902
NGL (MBbls)	1,109			577			2,500			1,608
Natural gas (MMcf)	21,501			25,788			62,335			78,342
Total volumes (MBoe)	7,337			8,247			20,816			25,567
Average daily total volumes (MBoe/d)	79.7			89.6			76.2			93.7
Average prices—as reported(1)
Oil (per Bbl)	$	94.60		$	105.87		$	97.12		$	98.39
NGL (per Bbl)	$	35.84		$	36.35		$	37.84		$	34.49
Natural gas (per Mcf)	$	3.24		$	3.15		$	3.86		$	3.36
Total (per Boe)	$	49.01		$	55.68		$	53.08		$	54.43
Average prices—including impact of derivative contract settlements(2)
Oil (per Bbl)	$	94.86		$	99.66		$	95.85		$	99.49
NGL (per Bbl)	$	35.84		$	36.35		$	37.84		$	34.49
Natural gas (per Mcf)	$	3.37		$	3.45		$	3.64		$	3.44
Total (per Boe)	$	49.48		$	54.08		$	51.95		$	55.11

__________________


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


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

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The table below presents production by area of operation for the three and nine-month periods ended September 30, 2014 and 2013 and illustrates the impact of (i) the Company’s continued development of its Mid-Continent assets, (ii) the sale of the Gulf Properties in February 2014 and (iii) the sale of the Permian Properties in February 2013.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	Production (MBoe)	% of Total		Production (MBoe)	% of Total		Production (MBoe)	% of Total		Production (MBoe)	% of Total
Mid-Continent	6,292	85.8	%	4,596	55.7	%	16,280	78.2	%	12,851	50.3	%
Gulf of Mexico / Gulf Coast	—	—	%	2,429	29.5	%	1,321	6.3	%	7,961	31.1	%
Permian Basin	512	7.0	%	599	7.3	%	1,590	7.6	%	2,794	10.9	%
Other - west Texas	533	7.2	%	623	7.5	%	1,625	7.9	%	1,961	7.7	%
Total	7,337	100.0	%	8,247	100.0	%	20,816	100.0	%	25,567	100.0	%

Revenues

Exploration and production segment revenues from oil, natural gas and NGL sales decreased $99.6 million, or 21.7%, for the three-month period ended September 30, 2014, from the same period in 2013. Approximately $71.2 million of the total net decrease resulted from a 0.9 MMBoe, or 11.0%, decrease in combined production, stemming largely from a decrease in oil production due to the sale of the Gulf Properties in February 2014. The remainder of the decrease was primarily due to a decline in the average price received for oil production. Exploration and production segment revenues from oil, natural gas and NGL sales decreased $286.7 million, or 20.6%, for the nine-month period ended September 30, 2014 from the same period in 2013. Approximately $315.7 million of the total net decrease resulted from a 4.8 MMBoe, or 18.6%, decrease in combined production stemming largely from a decrease in oil production due to the sale of the Gulf Properties in February 2014 and the sale of the Permian Properties in February 2013. Partially offsetting this decrease was an increase in the average price received for natural gas and NGL production. As illustrated in the table above, the decrease in volumes in the Gulf of Mexico/Gulf Coast areas for the three and nine-month periods ended September 30, 2014 and the decrease in volumes for the Permian area for the nine-month period ended September 30, 2014 were partially offset by increased production from the Mid-Continent area, as the Company focused on its development of this area.

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 $42.1 million, or 33.6%, and $134.1 million, or 34.2%, for the three and nine-month periods ended September 30, 2014, respectively, compared to the same periods in 2013 primarily due to the decrease in total production and a decrease in production costs per Boe. During the three and nine-month periods ended September 30, 2014, production expense was $11.34 and $12.41 per Boe, respectively, down from the comparable 2013 period rates of $15.19 and $15.35 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 as a percentage of oil, natural gas and NGL revenue increased to approximately 2.3% for the three-month period ended September 30, 2014 from 1.9% for the same period of 2013 and to approximately 2.2% for the nine-month period ended September 30, 2014 from 1.8% for the same period of 2013 as taxable production from the Mid-Continent partially 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 $25.1 million and $109.0 million for the three and nine-month periods ended September 30, 2014, respectively, compared to the same periods in 2013. These decreases are largely a result of the decrease in the Company’s combined production volumes for the respective periods as well as a decrease in the depreciation and depletion rate per Boe to $15.34 and $15.61 for the three and nine-month periods ended September 30, 2014, respectively, from $16.69 and $16.98 for the three and nine-month periods ended September 30, 2013, respectively. The decrease in the depreciation and depletion rates is primarily due to the sale of the Gulf Properties in February 2014 and, to a lesser extent, the sale of the Permian Properties in 2013.

Accretion of asset retirement obligations decreased $7.4 million and $20.1 million for the three and nine-month periods ended September 30, 2014, respectively, compared to the same periods in 2013, primarily due to the assumption by the buyer of asset retirement obligations associated with the Gulf Properties sold in February 2014.

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The Company incurred an impairment of $164.8 million for the nine-month period ended September 30, 2014 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. There was no full cost ceiling impairment for the three-month period ended September 30, 2014 or the three and nine-month periods ended September 30, 2013.

The Company recorded a (gain) loss on commodity derivative contracts of $(132.6) million and $132.8 million for the three-month periods ended September 30, 2014 and 2013, respectively, as reflected in the accompanying unaudited condensed consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(3.4) million and $12.5 million, respectively. The Company recorded a (gain) loss on commodity derivative contracts of $(4.8) million and $70.1 million for the nine-month periods ended September 30, 2014, and 2013, respectively, which includes net cash payments upon settlement of $92.9 million and $12.8 million, respectively. Included in these net cash payments are $69.6 million and $29.3 million of payments for early settlements of commodity derivative contracts primarily as a result of the sale of the Gulf Properties in February 2014 and the Permian Properties in February 2013, respectively.

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 oil and natural gas price swaps, 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 oil and natural gas price swaps.

The Company recorded a loss on the sale of assets of $398.9 million for the nine-month period ended September 30, 2013 as a result of the sale of the Permian Properties in February 2013. No gain or loss was recognized for the sale of the Gulf Properties in February 2014. See “Note 3 - Divestitures” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional discussion of the sale of the Gulf Properties.

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

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.

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Set forth in the table below is financial and operational information for the drilling and oil field services segment for the three and nine-month periods ended September 30, 2014 and 2013.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Results (in thousands)
Revenues	$	51,082		$	44,527		$	150,054		$	141,364
Inter-segment revenue	(29,734		)	(28,335		)	(92,774		)	(91,713		)
Total revenues	21,348			16,192			57,280			49,651
Operating expenses	22,503			23,952			60,752			75,231
Impairment	—			516			3,133			11,104
Loss from operations	$	(1,155	)	$	(8,276	)	$	(6,605	)	$	(36,684	)

Drilling rig statistics
Average number of operational rigs owned during the period	27.0			27.0			27.0			28.0
Average number of rigs working for third parties	5.9			5.0			5.3			3.9
Number of days drilling for third parties	530			455			1,453			1,071
Average drilling revenue per day per rig drilling for third parties(1)	$	14,411		$	14,623		$	14,725		$	14,838

Rig status - September 30							2014			2013
Working for SandRidge							12			11
Working for third parties							6			5
Idle(2)							9			11
Total operational							27			27
Non-operational(3)							3			3
Total rigs							30			30

____________________


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


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


(3)	Non-operational rigs at September 30, 2014 and September 30, 2013 are held for sale.

Drilling and oil field services segment revenues increased $5.2 million and $7.6 million for the three and nine-month periods ended September 30, 2014, respectively, compared to the same periods in 2013 primarily due to an increase in revenue from third party working interests for work performed on wells in which the Company also has an interest, as well as an increase in work performed for third parties during the three-month period ended September 30, 2014. These increases were partially offset by a decrease in revenue from oil field services supplies due to the sale of the northwest Oklahoma location in 2013. Drilling and oil field services segment operating expenses decreased $1.4 million during the three-month period ended September 30, 2014, compared to the same period in 2013 due primarily to an increased focus on capital discipline by management. Drilling and oil field services segment operating expenses decreased $14.5 million during the nine-month period ended September 30, 2014, compared to the same period in 2013 due primarily to costs incurred in the first quarter of 2013 associated with maintenance performed on rigs that were stacked as a result of the sale of the Permian Properties, as well as an increased focus on capital discipline by management. During the three-month period ended September 30, 2013, and the nine-month periods ended September 30, 2014 and 2013, the Company recorded impairments of approximately $0.5 million, $3.1 million, and $11.1 million respectively, on certain drilling assets identified for sale in order to adjust their carrying values to fair value.

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Midstream Services Segment

Midstream services segment revenues consist mostly of revenue from gas marketing, which is a very low-margin business, and revenues from coordinating the delivery of electricity to the Company’s exploration and production operations in the Mid-Continent area.

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 incurs 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.

Electrical Provision. The Company owns an electrical transmission system in the Mid-Continent that coordinates the delivery of 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 for 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 and nine-month periods ended September 30, 2014 and 2013.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Results (in thousands)
Operating revenues	$	31,132		$	37,876		$	115,846		$	115,748
Construction contract	—			—			—			23,253
Inter-segment revenue	(19,210		)	(23,735		)	(71,405		)	(74,896		)
Total revenues	11,922			14,141			44,441			64,105
Operating expenses	15,140			21,832			51,414			58,958
Construction contract	—			—			—			23,253
Loss from operations	$	(3,218	)	$	(7,691	)	$	(6,973	)	$	(18,106	)

Gas Marketed
Volumes (MMcf)	1,855			2,031			5,557			6,040
Average price	$	3.84		$	3.40		$	4.36		$	3.63

Midstream services segment revenues and expenses decreased $2.2 million and $6.7 million, respectively, for the three-month period ended September 30, 2014 compared to the same period in 2013. Segment revenues and expenses, excluding construction contract revenue and expense increased $3.6 million and decreased $7.5 million, respectively, for the nine-month period ended September 30, 2014 compared to the same period in 2013. During the second quarter of 2014, the fee structure for electric usage was revised, which resulted in decreasing revenues for electrical transmission services for the three-month period ended September 30, 2014 and decreasing expenses for electrical transmission for the three and nine-month periods ended September 30, 2014. The increase in revenue for the nine-month period ended September 30, 2014 compared to the same period in 2013 was due primarily to an increase in electrical transmission services provided to third-party working interest owners in the Mid-Continent during 2014 compared to 2013, as well as an increase in gas compressor and generator rentals for the periods. These increases were partially offset by changes in the fee structure for electric usage as noted above. Additionally, operating expenses for the nine-month period ended September 30, 2013 include an impairment of $2.1 million on certain midstream pipe inventory and natural gas compressors due to the determination that their future use was limited. No significant impairment was taken during the three and nine-month periods ended September 30, 2014.

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During the second quarter of 2013, the Company substantially completed the construction of a series of electrical transmission expansion and upgrade projects for a third party and, as a result, recognized construction contract revenue and costs equal to $23.3 million. For more information about these projects, see “Note 8 - Construction Contract” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report.

Consolidated Results of Operations

Revenues

The Company’s consolidated revenues for the three and nine-month periods ended September 30, 2014 and 2013 are presented in the table below.



	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
	(In thousands)
Revenues
Oil, natural gas and NGL	$	359,613	$	459,211	$	1,104,835	$	1,391,510
Drilling and services	21,348		16,149		57,280		49,597
Midstream and marketing	11,922		14,624		44,706		42,854
Construction contract	—		—		—		23,253
Other	1,224		3,619		5,056		11,066
Total revenues(1)	$	394,107	$	493,603	$	1,211,877	$	1,518,280

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(1)

Includes $37.1 million and $54.3 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended September 30, 2014 and 2013, respectively. Includes $123.2 million and $153.8 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the nine-month periods ended September 30, 2014 and 2013, 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 and construction contract revenues under “Results by Segment—Midstream Services Segment.”

Other revenues decreased for the three and nine-month periods ended September 30, 2014 compared to the same periods in 2013 due primarily to a decrease in revenues from the Bullwinkle and other offshore platforms, which were included in the sale of the Gulf Properties in February 2014.

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Expenses

The Company’s consolidated expenses for the three and nine-month periods ended September 30, 2014 and 2013 are presented below.



	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013 (Restated)		2014			2013 (Restated)
	(In thousands)
Expenses
Production	$	82,664		$	124,571	$	256,473		$	389,911
Production taxes	8,380			8,816		24,027			24,819
Cost of sales	15,992			13,773		38,942			45,438
Midstream and marketing	11,405			13,224		40,659			39,954
Construction contract	—			—		—			23,253
Depreciation and depletion—oil and natural gas	112,569			137,639		325,021			434,068
Depreciation and amortization—other	14,417			15,270		45,350			46,628
Accretion of asset retirement obligations	1,116			8,472		7,927			28,051
Impairment	54			687		167,966			16,330
General and administrative	24,584			37,714		86,115			172,301
Employee termination benefits	5			2,256		8,927			120,374
(Gain) loss on derivative contracts	(132,575		)	132,808		(4,792		)	70,051
(Gain) loss on sale of assets	(995		)	539		(978		)	398,364
Total expenses(1)	$	137,616		$	495,769	$	995,637		$	1,809,542

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(1)

Includes $(3.3) million and $37.9 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the three-month periods ended September 30, 2014 and 2013, respectively. Includes $72.8 million and $143.4 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the nine-month periods ended September 30, 2014 and 2013, respectively. Expenses attributable to noncontrolling interests in consolidated VIEs for the nine-month periods ended September 30, 2014 and 2013 include $29.9 million of allocated full cost ceiling impairment and $71.7 million of allocated loss on sale of assets associated with the sale of the Permian Properties, 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 and (gain) loss on sale of assets under “Results by Segment—Exploration and Production Segment,” discussion of cost of sales and impairment under “Results by Segment— Drilling and Oil Field Services Segment” and discussion of midstream and marketing and construction contract expenses under “Results by Segment—Midstream Services Segment.”

General and administrative expenses decreased $13.1 million, or 34.8%, for the three-month period ended September 30, 2014 from the same period in 2013 due primarily to decreases of (i) $7.5 million in compensation, largely resulting from a decrease in headcount during 2014 as well as a decrease in the value of the Company’s performance units, (ii) $3.8 million in professional services related primarily to decreases in legal and consulting fees, and (iii) $1.4 million in costs related to a stockholder consent solicitation that occurred in 2013. General and administrative expenses decreased $86.2 million, or 50.0%, for the nine-month period ended September 30, 2014 from the same period in 2013 due primarily to a decrease of $22.0 million in costs related to a stockholder consent solicitation that occurred in 2013, as well as decreases of (i) $38.5 million in compensation, (ii) $9.6 million in professional services costs, (iii) $3.8 million in promotional and advertising costs, and (iv) $4.1 million in other corporate support costs primarily as a result of corporate cost cutting measures and a decrease in headcount during 2014.

Employee termination benefits in the nine-month period ended September 30, 2014 represent severance costs of $8.9 million incurred in conjunction with the sale of the Gulf Properties. Employee termination benefits of $2.3 million and $120.4 million for the three and nine-month periods ended September 30, 2013 represent severance costs associated with former Company executives. Of the total employee termination benefits for the nine-month period ended September 30, 2013, approximately $94.7 million, including amounts associated with the accelerated vesting of restricted stock awards, was attributable to the Company’s former Chairman and CEO.

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

The Company’s other income (expense), taxes and net income attributable to noncontrolling interest for the three and nine-month periods ended September 30, 2014 and 2013 are presented in the table below.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013 (Restated)			2014			2013 (Restated)
	(In thousands)
Other income (expense)
Interest expense	$	(59,783	)	$	(61,385	)	$	(183,689	)	$	(208,454	)
Loss on extinguishment of debt	—			—			—			(82,005		)
Other income (expense), net	(273		)	658			3,159			1,163
Total other expense	(60,056		)	(60,727		)	(180,530		)	(289,296		)
(Loss) income before income taxes	196,435			(62,893		)	35,710			(580,558		)
Income tax (benefit) expense	(1,064		)	2,363			(2,131		)	7,300
Net income (loss)	197,499			(65,256		)	37,841			(587,858		)
Less: net income attributable to noncontrolling interest	40,161			16,191			49,733			9,393
Net income (loss) attributable to SandRidge Energy, Inc.	$	157,338		$	(81,447	)	$	(11,892	)	$	(597,251	)

Interest expense for the three and nine-month periods ended September 30, 2014 and 2013 consisted of the following:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(In thousands)
Interest expense
Interest expense on debt	$	63,606		$	63,590		$	190,928		$	214,051
Amortization of debt issuance costs, discounts and premium	2,477			2,484			7,439			8,643
Interest rate swap loss	—			—			—			14
Capitalized interest	(6,190		)	(4,281		)	(14,132		)	(12,667		)
Total	59,893			61,793			184,235			210,041
Less: interest income	(110		)	(408		)	(546		)	(1,587		)
Total interest expense	$	59,783		$	61,385		$	183,689		$	208,454

Total interest expense decreased $24.8 million for the nine-month period ended September 30, 2014 compared to the same period in 2013, primarily due to a reduction in interest expense associated with the senior notes repurchased and redeemed in the first quarter of 2013. See “Note 9 - 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 2013.

The Company recognized a loss on extinguishment of debt of $82.0 million for the nine-month period ended September 30, 2013 in connection with the redemption and repurchase of certain of its senior notes. This loss represents the premium paid to redeem the notes and the expense incurred to write off the remaining unamortized debt issuance costs associated with the notes.

The Company’s income tax benefit of $2.1 million for the nine-month period ended September 30, 2014 is primarily related to a reduction in the amount of $1.3 million in the Company’s gross unrecognized tax benefits following a favorable outcome pertaining to the Company’s state income tax audits and a reduction in federal alternative minimum tax (“AMT”) associated with the tax year ended December 31, 2013 in the amount of $1.2 million. With respect to the AMT, the Company reduced the current liability and a corresponding deferred tax asset each upon finalizing and filing the Company’s federal income tax return for the year ended December 31, 2013. As a result of reducing the deferred tax asset, the Company decreased its valuation allowance against it net deferred tax asset by $1.2 million. The Company's income tax expense of $7.3 million for the nine-month period ended September 30, 2013 is primarily related to AMT associated with the tax year ended December 31, 2013. The Company recorded a current liability and a corresponding deferred tax asset each in the amount of $4.7 million for the nine-month period ended September 30, 2013 for the AMT. As a result of recording a deferred tax asset, the Company increased its valuation allowance against its net deferred tax asset by $4.7 million.

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Net income attributable to noncontrolling interest represents the portion of net income attributable to third-party ownership in the Company’s consolidated VIEs and subsidiaries. Net income attributable to noncontrolling interest increased $24.0 million or 148.0% and $40.3 million or 429.5% for the three and nine-month periods ended September 30, 2014, respectively, from the same periods in 2013. The increase in income for the three-month period ended September 30, 2014 is primarily due to net gains recognized on the Royalty Trusts’ derivative contracts during the period compared to net losses recognized during the same period in 2013. Income for the nine-month period ended September 30, 2014 includes the impact of the full cost ceiling impairment attributable to noncontrolling interest of $29.9 million compared to the loss on the sale of the Permian Properties attributable to noncontrolling interest of $71.7 million included in the nine-month period ended September 30, 2013. This increase was partially offset by a decrease in revenues in 2014 compared to 2013 largely as a result of declining production for the Mississippian Trust I and the Mississippian Trust II.

Liquidity and Capital Resources

The Company’s primary sources of liquidity and capital resources are cash on hand, cash flows from operating activities, proceeds from monetizations of assets, borrowings under the senior credit facility and the issuance of equity and debt securities in the capital markets. As described in “2014 Developments and Outlook,” the Company received proceeds of approximately $702.6 million, net of working capital adjustments and post-closing adjustments, for the sale of its Gulf Properties in February 2014.

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, interest payments on its outstanding debt, the repurchase of shares of the Company’s outstanding common stock 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 2014 budget for capital expenditures, including expenditures related to the Company’s drilling programs for the Permian Trust and Mississippian Trust II and net of $205.6 million in drilling carries estimated to be received in 2014, was approximately $1.5 billion. See “Note 6 - Property, Plant and Equipment” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for discussion of the drilling carries. The Company expects to fund its near term capital and debt service requirements and working capital needs with cash on hand ($0.6 billion at September 30, 2014), cash flows from operations and available borrowing capacity under its $1.2 billion senior credit facility, which is undrawn, other than $10.4 million in letters of credit secured by the senior credit facility that reduce availability on a dollar for dollar basis, at September 30, 2014. The Company has no maturities of long-term debt prior to 2020, and may choose to issue new long-term debt, subject to market availability and as permitted by the terms of the Company’s other current debt instruments, 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 an increasing portion of its funding needs to be covered by increased cash flows from operations, and may issue long-term debt, subject to the terms of the Company’s credit facility, or equity or monetize assets to cover any difference between cash flow from operations and capital needs. Further, the Company’s capital expenditures could be curtailed if the Company’s cash flows decline from expected levels.

The Company and one of its wholly owned subsidiaries are parties to development agreements with the Permian Trust and Mississippian Trust II that obligate the Company to drill, or cause to be drilled, a specified number of wells within specific areas of mutual interest for each Royalty Trust by March 31, 2016 and December 31, 2016, respectively. The Company satisfied its drilling obligation to the Permian Trust in November 2014 and expects to satisfy its drilling obligation to the Mississippian Trust II in the first quarter of 2015. In addition, production targets contained in certain gathering and treating arrangements require the Company to incur capital expenditures or make associated shortfall payments.

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 over $107.00 per Bbl in June 2014 to below $56.00 per Bbl in December 2014. In November 2014, WTI crude oil prices ranged from $78.77 per Bbl in June 2014 to below $65.94 per Bbl. Henry Hub natural gas prices declined from over $8.15 per MMBtu in February 2014 to $3.53 per MMBtu in late October 2014. In November 2014, Henry Hub natural gas prices ranged from $3.67 per MMBtu to $4.41 per MMBtu. The Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows. To this end, collars and fixed price swap contracts are in place for portions of expected oil

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and natural gas production in both 2014 and 2015 and for a portion of expected oil production in 2016. Currently, no collars or fixed price swap contracts are in place for any of the Company’s oil and natural gas production beyond 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, potentially resulting in a full cost pool ceiling impairment and also adversely impacting the Company’s ability to comply with the financial covenants under its senior credit facility, which in turn would limit borrowings to fund capital expenditures. The Company may increase or decrease planned capital expenditures depending on oil and natural gas prices and the availability of funding from the sources described above.

The Company may from time to time seek to retire or purchase its outstanding debt securities through cash purchases and/or exchanges in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.

As of September 30, 2014, the Company’s cash and cash equivalents were $0.6 billion, including $7.6 million attributable to the Company’s consolidated VIEs which is available to satisfy only obligations of the VIEs. The Company had approximately $3.2 billion in total debt outstanding and $10.4 million in outstanding letters of credit with no amount outstanding under its senior credit facility at September 30, 2014. As of and during the three and nine-month period ended September 30, 2014, the Company was in compliance with applicable covenants under its senior credit facility and outstanding Senior Notes. As of December 29, 2014, the Company’s cash and cash equivalents were approximately $139.5 million, including $9.4 million attributable to the Company’s consolidated VIEs. Additionally, there was no amount outstanding under the Company’s senior credit facility and $11.6 million in outstanding letters of credit which reduced the availability under the senior credit facility to $1.2 billion.

Working Capital

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

At September 30, 2014, the Company had a working capital surplus of $333.5 million compared to a surplus of $308.0 million at December 31, 2013. Current assets decreased by $237.1 million and current liabilities decreased by $262.6 million at September 30, 2014, compared to December 31, 2013. The decrease in current assets is primarily due to a $224.4 million decrease in cash and cash equivalents, which is primarily the result of cash used in operations and for capital expenditures during 2014, partially offset by the receipt of proceeds from the sale of the Gulf Properties in February 2014. Also contributing to the decrease in current assets, were decreases of $32.5 million in prepaid expenses, due primarily to the sale of the Gulf Properties, and $18.7 million in accounts receivable, largely resulting from fluctuations in the timing and amount of collections of receivables. These were partially offset by an increase of $41.1 million in the net asset position of the Company’s current derivative contracts. The change in current liabilities is primarily due to a decrease of $159.8 million in accounts payable and accrued expenses largely due to (i) the sale of the Gulf Properties, (ii) interest payments made on the senior notes, (iii) the payment of accrued 2013 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 nine-month period ended September 30, 2014. Additionally, the current asset retirement obligation decreased by $87.1 million, primarily due to the sale of the Gulf Properties, and the net liability position of the Company’s current derivative contracts decreased by $34.3 million. These decreases in current liabilities were slightly offset by an increase of $25.3 million as a result of accruing the CO₂shortfall penalty attributable to the nine-month period ended September 30, 2014, and a liability of $10.4 million recognized as a result of the Company’s guarantee on behalf of Fieldwood of certain plugging and abandonment obligations as of September 30, 2014.

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Cash Flows

The Company’s cash flows for the nine-month periods ended September 30, 2014 and 2013 are presented in the following table and discussed below:



	Nine Months Ended September 30,
	2014			2013
	(In thousands)
Cash flows provided by operating activities	$	395,684		$	595,007
Cash flows (used in) provided by investing activities	(374,091		)	1,388,289
Cash flows used in financing activities	(246,010		)	(1,372,805		)
Net (decrease) increase in cash and cash equivalents	$	(224,417	)	$	610,491

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 NGL production, the quantity of oil, natural gas and NGLs it produces, 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 provided by operating activities for the nine-month period ended September 30, 2014 decreased from the comparable period in 2013 due primarily to a decrease in oil and natural gas production as a result of the sale of the Gulf Properties in February 2014, which was slightly offset by an increase in prices for natural gas and NGLs and an increase in production in the Mid-Continent area. Also contributing to the decrease was an increase in payments made on the settlement of derivative contracts, including payments for early settlements of commodity derivative contracts as a result of the Gulf Properties in February 2014, and changes in operating assets and liabilities during 2014.

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 $374.1 million for the nine-month period ended September 30, 2014 compared to cash provided by investing activities of $1.4 billion for the same period in 2013. During the nine-month period ended September 30, 2014, the Company had capital expenditures, excluding acquisitions, of $1.1 billion, which were partially offset by proceeds from the sale of assets of $714.3 million primarily as a result of the sale of the Gulf Properties. During the nine-month period ended September 30, 2013, the Company received proceeds of $2.6 billion from the sale of the Permian Properties, which were partially offset by capital expenditures during the period.

Capital Expenditures. The Company’s capital expenditures, on an accrual basis, by segment for the nine-month periods ended September 30, 2014 and 2013 are summarized below:



	Nine Months Ended September 30,
	2014		2013
	(In thousands)
Capital Expenditures
Exploration and production	$	1,056,568	$	1,008,869
Drilling and oil field services	10,877		4,657
Midstream services	25,810		46,883
Other	27,282		38,043
Capital expenditures, excluding acquisitions	1,120,537		1,098,452
Acquisitions	16,920		15,527
Total	$	1,137,457	$	1,113,979

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Capital expenditures, excluding acquisitions, increased by $22.1 million for the nine-month period ended September 30, 2014 from the same period in 2013 primarily due to an increase in drilling and leasehold expenditures in the Mid-Continent area.

Cash Flows from Financing Activities

The Company’s financing activities used $246.0 million of cash for the nine-month period ended September 30, 2014 compared to $1.4 billion in the same period in 2013. The decrease is due primarily to the redemption of $1.1 billion of senior notes as well as the $62.0 million premium paid in connection with the redemption of these notes during the nine-month period ended September 30, 2013. During the nine-month period ended September 30, 2014, the Company paid $44.1 million for the early settlement of financing derivatives as a result of the sale of the Gulf Properties, and paid $17.5 million to repurchase shares of the Company’s common stock, as noted below. Partially offsetting these payments was a decrease of $23.0 million in treasury stock purchases as a result of a reduction in shares of restricted stock that were traded for taxes upon vesting during the nine-month period ended September 30, 2014 compared to the same period in 2013.

Share Repurchase Program. On September 4, 2014, the Company announced that its Board of Directors had approved a program to repurchase up to $200.0 million of the Company's common stock. Payment for shares repurchased under the program have been and will be funded using the Company's working capital. During the three-month period ended September 30, 2014, 3.5 million shares were repurchased under the program for approximately $17.5 million and were immediately retired. See “Note 13 - Equity” to the accompanying condensed consolidated financial statements for additional discussion of the share repurchase program.

Indebtedness

Long-term debt consists of the following at September 30, 2014 (in thousands):



8.75% Senior Notes due 2020, net of $4,768 discount	$	445,232
7.5% Senior Notes due 2021, including premium of $3,598	1,178,598
8.125% Senior Notes due 2022	750,000
7.5% Senior Notes due 2023, net of $3,529 discount	821,471
Total debt	$	3,195,301

The indentures governing the Senior Notes contain covenants imposing certain restrictions on the Company’s activities, including, but not limited to, limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and during the three and nine-month periods ended September 30, 2014, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Notes.

Maturities of Long-Term Debt. As of September 30, 2014, there are no maturities of long-term debt until January 2020.

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. In connection with the amendment and restatement of the senior credit facility in October 2014, the Company’s borrowing base was increased to $1.2 billion (previously $775.0 million). Initially, the availability of the borrowing base will be limited to a facility amount of $900.0 million. Upon delivery by the Company of a written request and the payment of additional up-front fees to the lenders, the facility amount may be increased up to the full borrowing base. The next redetermination is expected to take place in April 2015. Quarterly, the Company pays a commitment fee assessed at annual rates ranging from 0.375% to 0.5% on any available portion of the senior credit facility. 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, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base.

At September 30, 2014, the Company had no amount outstanding under the senior credit facility and $10.4 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $764.6 million. As of and during the three and nine-month periods ended September 30, 2014, the Company was in compliance with all applicable financial covenants under the senior credit facility.

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On November 14, 2014, the Company and its lenders amended the credit agreement to waive certain defaults that may have arisen as a result of the application of any new accounting treatment to the under delivery penalty described in “Note 2 - Restatement of Previously Issued Financial Statements” and extend the period for delivering the financial statements contained in this report.

For more information about the senior credit facility and the Senior Notes, see “Note 9 - Long-Term Debt” to the unaudited condensed consolidated financial statements included in this Quarterly Report.

Contractual Obligations and Off-Balance Sheet Arrangements

The Company’s contractual obligations include 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. The sale of the Gulf Properties in February 2014 resulted in the following changes to contractual obligations presented in the 2013 Form 10-K/A.

•

Asset Retirement Obligations. As of February 25, 2014, the date of the sale, asset retirement obligations associated with the divested Gulf Properties were assumed by Fieldwood. The total obligation assumed was $366.0 million, with approximately $81.4 million due in 2014, $34.2 million due in 2015, $51.8 million due in 2016, $52.4 million due in 2017, $11.7 million due in 2018, and $134.5 million due thereafter.


•	Guarantees. As of September 30, 2014, the fair value of the Company’s guarantees of plugging and abandonment obligations associated with the Gulf Properties was $10.4 million. For additional information about the guarantees, which could extend through February 2015, see “Note 3 - Divestitures” to the unaudited condensed consolidated financial statements included in this Quarterly Report.

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 2013 Form 10-K/A. 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 14 - Income Taxes” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for more discussion on maintaining the valuation allowance against the Company’s net deferred tax asset.

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

The Company was in a cumulative negative earnings position until the 36-month period ended December 31, 2012 at which time it reached cumulative positive earnings. However, as a result of the Company closing the sale of the 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. See “Note 3 - Divestitures” to the Company’s unaudited condensed consolidated financial statements included in this Quarterly Report for discussion of the sale of the Permian Properties. Based on net book value, historical costs and proved reserves as of February 26, 2013, the Company recorded a loss on the sale of $398.9 million, which caused the Company to report a loss for the year ended December 31, 2013. The Company remains in a cumulative negative earnings position through the 36-month period ended September 30, 2014. The resulting 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.

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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 minor changes in the supply of and demand for oil and natural gas and a variety of additional factors that are beyond the Company’s control. Due to these factors, management has placed a lower weight on the prospects of future earnings in its overall analysis of the valuation allowance.

In determining whether to maintain the valuation allowance, management concluded that the objectively verifiable negative evidence of cumulative negative earnings for the 36-month period ending September 30, 2014, 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, 2013 was $702.7 million.

Additionally, at December 31, 2013, the Company had valuation allowances totaling $50.8 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 use of interest rate swaps to manage its variable interest rate debt in prior periods 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, collars and basis swaps. At September 30, 2014, the Company’s commodity derivative contracts consisted of fixed price 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.

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. If the market price is between the ceiling price and the purchased put, no payments are due from either party.

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. Settlement for oil derivative contracts occurs in the succeeding month or quarter and natural gas derivative contracts are settled in the production month or quarter.

At September 30, 2014, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps



	Notional (MBbls)	Weighted Average Fixed Price
October 2014 - December 2014	1,115	$	98.78
January 2015 - December 2015	5,588	$	92.44
January 2016 - December 2016	1,464	$	88.36

Natural Gas Price Swaps

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Oil Collars - Three-way



	Notional (MBbls)	Sold Put	Purchased Put	Sold Call
October 2014 - December 2014	2,070	$70.00	$90.20	$100.00
January 2015 - December 2015	4,576	$76.56	$90.28	$103.48
January 2016 - December 2016	2,556	$83.13	$90.00	$100.85

Natural Gas Collars



	Notional (MMcf)	Collar Range
October 2014 - December 2014	236	$4.00	—	$7.78
January 2015 - December 2015	1,010	$4.00	—	$8.55

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 $(132.6) million and $132.8 million for the three-month periods ended September 30, 2014 and 2013, respectively, as reflected in the accompanying unaudited condensed consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(3.4) million and $12.5 million, respectively. The Company recorded a (gain) loss on commodity derivative contracts of $(4.8) million and $70.1 million for the nine-month periods ended September 30, 2014, and 2013, respectively, which includes net cash payments upon settlement of $92.9 million and $12.8 million, respectively. Included in these net cash payments are $69.6 million and $29.3 million of payments for early settlements of commodity derivative contracts primarily as a result of the sale of the Gulf Properties in February 2014 and the Permian Properties in February 2013, respectively.

See “Note 10 - 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 September 30, 2014, 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 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 4 - Variable Interest Entities” to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information on the Permian Trust’s and the Mississippian Trust II’s derivative contracts.

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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 23 financial institutions with commitments ranging from 1.00% to 6.00% of the borrowing base as of September 30, 2014.

Interest Rate Risk. The Company is exposed to interest rate risk on its long-term fixed rate debt and will be exposed to variable interest rates if it draws on its 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. The Company had no outstanding variable rate debt as of September 30, 2014.

Prior to its maturity on April 1, 2013, the Company had a $350.0 million notional interest rate swap agreement, which effectively fixed the variable interest rate on the Senior Floating Rate Notes at an annual rate of 6.69% for periods prior to their repurchase and redemption in the third quarter of 2012. The interest rate swap was not designated as a hedge.

The Company recorded a loss on its interest rate swap of $0.01 million for the nine-month period ended September 30, 2013, respectively, which is included in interest expense in the unaudited condensed consolidated statements of operations. Included in the loss for the nine-month period ended September 30, 2013, are cash payments upon contract settlement of $2.4 million.

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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.

In the course of a routine review of the Company’s filings by the staff of the SEC, management has determined that a material weakness in internal control over financial reporting as further described below existed as of September 30, 2014. 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 September 30, 2014.

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 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.

Remediation Plan

The Company is remediating the material weakness by revising, clarifying and implementing accounting policies and controls related to the shortfall penalty and, among other things, implementing 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. Management believes the foregoing efforts will effectively remediate the material weakness. As the Company continues to evaluate and work to improve its internal control over financial reporting, management may execute additional measures to address the material weakness or modify the remediation plan described and will continue to review and make necessary changes to the overall design of its internal controls.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect its internal control over financial reporting.

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PART II. Other Information

ITEM 1. Legal Proceedings

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

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

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. 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.

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 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 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.

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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 Chief Executive Officer (“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 fifteen 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.

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 Company is cooperating with the investigation.

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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.

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 2013 Form 10-K/A.

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

The following table presents a summary of share repurchases made by the Company during the three-month period ended September 30, 2014.



Period	Total Number of Shares Purchased(1)(2)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program(2)	Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in Millions)
July 1, 2014 — July 31, 2014	339,585	$	6.70	N/A	N/A
August 1, 2014 — August 31, 2014	2,304	$	5.82	N/A	N/A
September 1, 2014 — September 30, 2014	3,524,505	$	4.99	3,500,000	$	182.5
Total	3,866,394			3,500,000

____________________

(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. For the three-month period ended September 30, 2014, 366,394 shares were reacquired at a weighted average price per share of $6.59 to satisfy tax obligations for vested employee stock awards.


(2)	Includes shares of common stock repurchased pursuant to a program approved by the Company’s Board of Directors and announced on September 4, 2014. Under the terms of the program, the Company may repurchase up to $200.0 million of the Company’s common stock. 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: January 8, 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	Third Amended and Restated Credit Agreement, dated as of October 22, 2014, among SandRidge Energy, Inc., as the Borrower, Barclays Bank PLC, Capital One, N.A., Royal Bank of Canada, Suntrust Bank, MUFG Union Bank, N.A. and Wells Fargo Bank, N.A., as Co-Syndication Agents, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, The Other Lenders Party thereto, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, Sole Lead Arranger and Sole Book Manager	8-K	001-33784	10.1	10/24/2014
10.2	Amendment No. 1 to the Third Amended and Restated Credit Agreement and Waiver, dated as of November 14, 2014, to the Third Amended and Restated Credit Agreement, dated as of October 22, 2014, among SandRidge Energy, Inc., a Delaware corporation, each Lender from time to time party thereto, and Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer.	8-K	001-33784	10.1	11/14/2014
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					*