10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2015

OR

¨ 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)
	(405) 429-5500
	(Registrant’s telephone number, including area code)
	Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, $0.001 par value		New York Stock Exchange
	Securities registered pursuant to Section 12(g) of the Act:
	None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes ¨ No þ

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 ¨

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 ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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. (Check one):

Large accelerated filer  o	Accelerated filer þ
Non-accelerated filer o (Do not check if 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 ¨ No þ

The aggregate market value of our common stock held by non-affiliates on June 30, 2015 was approximately $447.7 million based on the closing price as quoted on the New York Stock Exchange. As of March 23, 2016, there were 718,226,053 shares of our common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company’s definitive proxy statement for the 2016 Annual Meeting of Stockholders are incorporated by reference in Part III.

SANDRIDGE ENERGY, INC.

2015 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

Item		Page
	PART I
1.	Business	1
1A.	Risk Factors	29
1B.	Unresolved Staff Comments	43
2.	Properties	44
3.	Legal Proceedings	45
4.	Mine Safety Disclosures	51
	PART II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52
6.	Selected Financial Data	55
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	57
7A.	Quantitative and Qualitative Disclosures About Market Risk	83
8.	Financial Statements and Supplementary Data	85
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
9A.	Controls and Procedures	87
9B.	Other Information	88
	PART III
10.	Directors, Executive Officers and Corporate Governance	89
11.	Executive Compensation	90
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	91
13.	Certain Relationships and Related Transactions and Director Independence	92
14.	Principal Accounting Fees and Services	93
	PART IV
15.	Exhibits and Financial Statement Schedules	94

Certain Defined Terms

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. In addition, this report includes terms commonly used in the oil and natural gas industry, which are defined in the “Glossary of Oil and Natural Gas Terms” beginning on page 26.

Information Regarding Forward-Looking Statements

Various statements contained in this report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are 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 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, pending dispositions, 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, financial performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. The Company has based these 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 this report, including the following:

• risks associated with drilling oil and natural gas wells;

• the volatility of oil, natural gas and natural gas liquids (“NGL”) prices;

• uncertainties in estimating oil, natural gas and NGL reserves;

• the need to replace the oil, natural gas and NGLs the Company produces;

• the Company’s ability to execute its growth strategy by drilling wells as planned;

• the amount, nature and timing of capital expenditures, including future development costs, required to develop the Company’s undeveloped areas;

• concentration of operations in the Mid-Continent region of the United States;

• risks associated with obligations to deliver minimum volumes of natural gas under long-term contracts, including the risk that the Company will incur significant monetary penalties for under-delivery;

• limitations of seismic data;

• the potential adverse effect of commodity price declines on the carrying value of the Company’s oil and natural properties;

• severe or unseasonable weather that may adversely affect production;

• availability of satisfactory oil, natural gas and NGL marketing and transportation;

• availability and terms of capital to fund capital expenditures;

• amount and timing of proceeds of asset monetizations;

• substantial existing indebtedness and limitations on operations resulting from debt restrictions and financial covenants;

• potential financial losses or earnings reductions from commodity derivatives;

• potential elimination or limitation of tax incentives;

• competition in the oil and natural gas industry;

• general economic conditions, either internationally or domestically or in the areas where the Company operates;

• costs to comply with current and future governmental regulation of the oil and natural gas industry, including environmental, health and safety laws and regulations, and regulations with respect to hydraulic fracturing and the disposal of produced water; and

• the need to maintain adequate internal control over financial reporting.

PART I

Item 1.        Business

GENERAL

SandRidge Energy, Inc. is an energy company engaged in the exploration, development and production of crude oil, natural gas and NGLs. The Company’s primary area of operation is the Mid-Continent in Oklahoma and Kansas. The Company owns and operates additional interests in west Texas and acquired properties located in the Rockies in Colorado in December 2015. Additionally, the Company owned interests in the Gulf of Mexico and Gulf Coast until February 2014, as discussed under “2014 Divestiture” below.

As of December 31, 2015, the Company had 4,411 gross (3,371.7 net) producing wells, a substantial portion of which it operates, and approximately 2,063,000 gross (1,476,000 net) total acres under lease. As of December 31, 2015, the Company had four rigs drilling in the Mid-Continent. Total estimated proved reserves as of December 31, 2015 were 324.6 MMBoe, of which approximately 80% were proved developed.

The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater gathering and disposal system and an electrical transmission system. Additionally, until January 2016, the Company operated a drilling and related oilfield services business.

The Company’s principal executive offices are located at 123 Robert S. Kerr Avenue, Oklahoma City, Oklahoma 73102 and the Company’s telephone number is (405) 429-5500. SandRidge makes available free of charge on its website at www.sandridgeenergy.com its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the Securities and Exchange Commission (“SEC”). Any materials that the Company has filed with the SEC may be read and copied at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549 or accessed via the SEC’s website address at www.sec.gov.

Business Strategy

SandRidge’s mission is to become a high-return, growth-oriented resource conversion company focused in the Mid-Continent and Rockies regions of the United States. In pursuit of its mission, the Company focuses on the following strategies:

Complementary Operating Areas. The Company’s primary areas of operation are the Mid-Continent area of Oklahoma and Kansas and the Niobrara Shale in the Colorado Rockies. In the Mid-Continent, the Company is able to (i) increase its technical expertise that it has developed as one of the most active drillers and operators in the region and leverage that expertise in the interpretation of geological and operational opportunities, (ii) achieve economies of scale and breadth of operations, both of which help to control costs, (iii) take advantage of investments in infrastructure including electrical delivery and saltwater gathering and disposal systems and (iv) opportunistically grow its holdings through acquisitions, farmouts and operations in this area to achieve production and reserve growth. With the recent acquisition of Rockies acreage and assets in Colorado’s North Park Basin, the Company intends to develop a proven oil resource play similar to that being developed in Colorado’s DJ Basin, both areas drawing from the oil rich Niobrara Shale. In the Rockies, the Company intends to apply its core competencies in developing medium depth formations and deploy its expertise in multi-stage fracture stimulation, artificial lift and extended and multi-lateral wellbore designs. Additionally, as operator of a majority of its wells, the Company has flexibility to utilize these competitive advantages to deliver strong, sustainable returns.

Preservation of Capital in Depressed Commodity Pricing Environment. Volatility of pricing can significantly impact the amount of revenue received for oil and natural gas production and the level of economic returns the Company receives for amounts invested in its exploration and development activities. Over time, costs to drill, complete and operate wells typically adjust to prevailing commodity price levels, resulting in improved and more certain returns; however, during periods of depressed oil and natural gas pricing, such as that which began during the second half of 2014 and is continuing, the Company preserves capital and liquidity by contracting its capital expenditures budget and high-grading locations for development. During such times, the Company capitalizes on in place infrastructure, such as the Company’s saltwater gathering and disposal and electrical systems, by focusing drilling efforts on locations that can most effectively make use of this existing infrastructure. Additionally, exploration programs are conducted within a high-graded inventory of locations that have a greater certainty of economic returns. The Company’s 2016 capital expenditures budget is approximately $285.0 million, with approximately $262.0 million designated for exploration and production activities.

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Focus on Cost Efficiency and Capital Allocation. By leveraging its experienced workforce, scalable operational structure and infrastructure systems, the Company is able to achieve cost efficiencies and sustainable returns in the Mid-Continent and Niobrara Shale in the Rockies. In the Mid-Continent, with a focus on lower-risk, high rate of return and repeatable drilling opportunities with long economic lives, the Company has made improvements in its multi-lateral wellbore designs, its completion designs, well site production facilities, utilization of pad drilling, its vendor contracts and spud-to-spud cycle time to further reduce its cost structure in the Mid-Continent. Further, due to the low pressure and shallow characteristics of the reservoirs the Company develops, the Company is able to maintain a low-cost operating structure and manage service costs. Similar opportunities exist in the development of the Niobrara Shale in the Rockies, where technologies developed in the Mid-Continent are transferable. The ability to drill multiple laterals from a single pad or single vertical wellbore is expected to facilitate cost-effective development of this oil rich resource play.

Mitigate Commodity Price Risk. As appropriate, the Company enters into derivative contracts to mitigate a portion of the commodity price volatility inherent in the oil and natural gas industry. By increasing the predictability of cash inflows for a portion of its future production, the Company is better able to mitigate funding risks for its longer term development plans and lock-in rates of return on its capital projects.

Develop Key Infrastructure Systems. By constructing a saltwater gathering and disposal system and electrical delivery system to service its Mid-Continent properties, the Company is able to produce oil and natural gas more efficiently and, therefore, more economically, giving it a competitive advantage over other operators in this rural area. Expertise developed by the Company in planning and executing large scale infrastructure and midstream projects in the Mid-Continent is being directly applied to the development of the Niobrara Shale.

Maintain Flexibility. The Company has multi-year inventories of both oil and natural gas drilling locations within its core operating area. Maintaining inventories of both oil and natural gas drilling locations allows the Company to efficiently direct capital toward projects with the most attractive returns.

Pursue Opportunistic Acquisitions. The Company periodically reviews acquisition targets to complement its existing asset base. The Company selectively identifies such targets based on several factors including relative value, hydrocarbon mix and location, and the relative fit of the Company’s core competencies and technical expertise and, when appropriate, seeks to acquire them at a discount to other opportunities.

Acquisitions and Divestitures

2016 Divestiture and Release from Treating Agreement

On January 21, 2016, the Company transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the West Texas Overthrust (“WTO”) and $11.0 million in cash to a wholly owned subsidiary of Occidental Petroleum Corporation (“Occidental”) and was released from all past, current and future claims and obligations under an existing 30-year treating agreement between the companies. For the year ended December 31, 2015, production, revenues and direct operating expenses for the conveyed oil and natural gas properties were 1.9 MMBoe, $14.6 million and $41.1 million, respectively. Additionally, during the year ended December 31, 2015, the Company accrued approximately $34.9 million in penalties related to the Company’s shortfall in meeting its 2015 annual CO₂ delivery requirement under the 30-year treating agreement that was terminated in accordance with the terms of the transaction.

The assets of Piñon Gathering Company, LLC (“PGC”), which were acquired by the Company in October 2015 as discussed further below, were included in the consideration conveyed to Occidental.

2015 Acquisitions

Piñon Gathering Company, LLC. In October 2015, the Company acquired the assets of and terminated a gas gathering agreement with PGC for $48.0 million in cash and $78.0 million principal amount of newly issued 8.75% Senior Secured Notes due 2020 (“Senior Secured Notes”). PGC owns approximately 370 miles of gathering lines supporting the natural gas production from the Company's Piñon field in the WTO.

Rockies Properties - North Park Basin. In December 2015, the Company acquired approximately 135,000 net acres in the North Park Basin, Jackson County, Colorado for approximately $191.1 million in cash, including post-closing adjustments. Also included in the acquisition were working interests in 16 wells previously drilled on the acreage. Additionally, the seller paid the Company $3.1 million for certain overriding interests retained in the properties.

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2014 Divestiture

Sale of Gulf of Mexico and Gulf Coast Properties. On February 25, 2014, the Company sold certain of its subsidiaries that owned the Company’s Gulf of Mexico and Gulf Coast oil and natural gas properties (collectively, the “Gulf Properties”), to Fieldwood Energy, LLC (“Fieldwood”) for $702.6 million, net of working capital adjustments and post-closing adjustments, and Fieldwood’s assumption of approximately $366.0 million of related asset retirement obligations. The Company used 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 the Company making cash payments of approximately $69.6 million. The Company retained a 2% overriding royalty interest in certain exploration prospects.

In accordance with the terms of the sale, the Company agreed to guarantee on behalf of the buyer certain plugging and abandonment obligations associated with the Gulf Properties for a period of up to one year from the date of closing. Additionally, the buyer agreed to indemnify the Company for any costs it may incur as a result of the guarantee. The Company did not incur any costs as a result of this guarantee, and was released from the obligation during the third quarter of 2015.

2013 Divestiture

Sale of Permian Properties. On February 26, 2013, the Company sold its oil and natural gas properties in the Permian Basin area of west Texas, excluding the assets associated with the SandRidge Permian Trust area of mutual interest (the “Permian Properties”) for net proceeds of $2.6 billion, including post-closing adjustments that were finalized in the third quarter of 2013. 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 and used the remaining proceeds to fund capital expenditures in the Mid-Continent and for general corporate purposes. Including final post-closing adjustments, the Company recorded a non-cash loss on the sale of $398.9 million, 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 contractual maturities to reduce volumes hedged in proportion to the anticipated reduction in daily production volumes due to the sale, which resulted in a loss on settlement of approximately $29.6 million.

PRIMARY BUSINESS OPERATIONS

The Company’s dominant segment is its exploration and production business, which explores for, develops and produces oil and natural gas. Financial information for this segment and the Company’s two other reportable business segments, the drilling and oilfield services and midstream services segments, is provided in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Note 23—Business Segment Information” to the Company’s consolidated financial statements in Item 8 of this report. The information below includes the interests and activities of SandRidge Mississippian Trust I (the “Mississippian Trust I”), SandRidge Permian Trust (the “Permian Trust”) and SandRidge Mississippian Trust II (the “Mississippian Trust II”) (collectively, the “Royalty Trusts”), including amounts attributable to noncontrolling interest, all of which are included in the exploration and production segment.

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The following table presents information concerning the Company’s exploration and production activities by geographic area of operation as of December 31, 2015, unless otherwise noted.

	Estimated Net Proved Reserves (MMBoe)	PV-10 (In millions)(1)		Daily Production (MBoe/d)(2)	Reserves/ Production (Years)(3)	Gross Acreage	Net Acreage	Capital Expenditures (In millions) (4)
Area
Mid-Continent	259.1	$	1,171.8	59.5	11.9	1,826,050	1,273,232	$	655.4
Rockies	27.6	18.4		0.5	—	148,509	134,933	—
West Texas	37.9	124.8		8.3	12.5	88,244	68,210	4.9
Total	324.6	$	1,315.0	68.3	13.0	2,062,803	1,476,375	$	660.3

____________________

(1) For a reconciliation of PV-10 to Standardized Measure, see “—Proved Reserves.” The Company’s total Standardized Measure was $1.3 billion at December 31, 2015.

(2) Average daily net production for the month of December 2015.

(3) Estimated net proved reserves as of December 31, 2015 divided by production for the month of December 2015 annualized.

(4) Capital expenditures for the year ended December 31, 2015 on an accrual basis.

Properties

Mid-Continent

The Company held interests in approximately 1,826,000 gross (1,273,000 net) leasehold acres primarily in Oklahoma and Kansas at December 31, 2015. Associated proved reserves at December 31, 2015 totaled 259.1 MMBoe, 85% of which were proved developed reserves, based on estimates prepared by Cawley, Gillespie & Associates, Inc., (“CG&A”) and the Company’s internal engineers. The Company’s interests in the Mid-Continent as of December 31, 2015 included 2,386 gross (1,392.2 net) producing wells with an average working interest of 59%. The Company had four rigs operating in the Mid-Continent as of December 31, 2015, all of which were drilling horizontal wells. The Company drilled a total of 165 wells in this area during 2015, of which 161 were horizontal wells and four were saltwater disposal wells.

Mississippian Formation. A key target for exploration and development within the Mid-Continent area is the Mississippian formation, which is an expansive carbonate hydrocarbon system located on the Anadarko Shelf in northern Oklahoma and southern Kansas. The top of this formation is encountered between approximately 4,000 and 7,000 feet and lies stratigraphically between various formations of Pennsylvanian age and the Devonian-aged Woodford Shale formation. The Mississippian formation can reach 1,000 feet in gross thickness and have targeted porosity zone(s) ranging between 20 and 150 feet in thickness. At December 31, 2015, the Company had approximately 1,732,000 gross (1,218,000 net) acres under lease in the Mississippian formation.

The Company has drilled approximately 1,675 wells in this formation as of December 31, 2015. From December 31, 2014 to December 31, 2015, the number of the Company’s producing horizontal wells in the Mississippian formation increased from 1,555 to 1,726. Of the wells the Company drilled in the Mississippian formation during 2015, three wells are subject to the royalty interests of the Mississippian Trust II. The Company fulfilled its drilling obligation to the Mississippian Trust II in March 2015.

Other Formations. The Company drilled 23 wells in the Chester formation and eight wells in the Woodford formation in 2015 in order to determine commerciality and initiate development of these productive formations.

Historically drilled with vertical wells, the Chester formation in the Northern Mid-Continent is currently being targeted for horizontal development. The formation, which lies beneath various Pennsylvanian-aged formations and above the Mississippian formation, is composed of stacked low permeability sandstone and carbonate layers interbedded with shale.  The top of the formation occurs at about 5,600 feet and ranges in thickness from less than 100 to over 1,000 feet. Individual target zones within the formation range from 15 to 50 feet in thickness.

Long regarded as the primary source rock for most Mid-Continent reservoirs, the Woodford formation is now itself being developed horizontally across much of Oklahoma. This Devonian-aged formation, which lies beneath the Mississippian formation and above various Lower Paleozoic formations, is stratigraphically equivalent to the Marcellus Shale in the

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Appalachian Basin and the Bakken Shale in the Williston Basin. It is composed of alternating layers of organic-rich shale and less organic-rich siliceous or carbonate-rich shale. The top of the formation in the exploration and development area ranges from 6,200 to 10,000 feet, and the thickness of the formation ranges from less than 50 to over 100 feet.

Gathering and Disposal and Electrical Systems. The Company’s electrical infrastructure, owned by the Company’s midstream services segment, and saltwater gathering and disposal system assist in the economically efficient production of oil and natural gas in the Mid-Continent. The Company’s electrical infrastructure, which consisted of approximately 1,122 miles of power lines and seven substations at December 31, 2015, coordinates the delivery of electricity to the Company’s Mid-Continent operations at a lower cost than electricity provided by on-site generation. Additionally, by building its own infrastructure in these rural areas, the Company has been able to provide sufficient electricity to its operations. The Company is also able to obtain lower electrical rates based on aggregated volumes. The saltwater gathering and disposal system, which included more than 150 active wells and approximately 1,150 miles of gathering lines at December 31, 2015, reduces the overall cost of water disposal, which directly reduces production costs. The system has a current injection capacity of over 2.0 million barrels of water per day.

Rockies

The Company acquired its Rockies assets, located in the North Park Basin in Jackson County, Colorado, in December 2015. At December 31, 2015, the properties consisted of approximately 149,000 gross (135,000 net) acres and operated working interests in 16 previously drilled producing wells with an average working interest of 100%. Associated proved reserves at December 31, 2015 were approximately 27.6 MMBoe, of which approximately 6% were proved developed reserves. The Rockies acreage is located within the Niobrara Shale play. The Niobrara Shale is characterized by numerous stacked pay reservoirs at depths of 5,500 to 9,000 feet with reservoir thickness over 450 feet.

West Texas

The Company’s west Texas oil and natural gas properties include properties in the WTO and the Permian Basin. As of December 31, 2015, the Company’s west Texas properties consisted of approximately 88,000 gross (68,000 net) leasehold acres, 2,009 gross (1,963.5 net) producing wells with an average working interest of 98%. Associated proved reserves at December 31, 2015 were 37.9 MMBoe, 100% of which were proved developed reserves. The Company did not drill any wells in this area during 2015.

As discussed in “2016 Divestiture and Release from Treating Agreement” above, the Company divested its WTO oil and natural gas properties in January 2016. Also, under the terms of the transaction, the Company was released from its past, current and future obligations under a 30-year treating agreement pursuant to which (i) the Company delivered natural gas produced in the WTO to Occidental’s CO₂ treatment plant in Pecos County, Texas (the “Century Plant”) and (ii) Occidental removed CO₂ from natural gas volumes delivered by the Company. The Company retained all methane gas after treatment. Under the agreement, the Company was required to deliver a total of approximately 3,200 Bcf of CO₂ during the agreement period. The Company was obligated to pay Occidental $0.25 per Mcf to the extent minimum annual CO₂ volume requirements were not met and $0.70 per Mcf to the extent the total contract delivery requirement was not met by the end of the contract term.

Proved Reserves

Preparation ofReserves Estimates

The estimates of oil, natural gas and NGL reserves in this report are based on reserve reports, the substantial majority of which were prepared by independent petroleum engineers. To achieve reasonable certainty, the Company’s engineers relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy, before consultation with independent petroleum engineers. Such consultation included review of properties, assumptions and any new data available. The Corporate Reservoir department’s internal reserves estimates and methodologies were compared to those prepared by independent petroleum engineers to test the reserves estimates and conclusions before the reserves estimates were included in this report. The accuracy of the reserve estimates is dependent on many factors, including the following:

• the quality and quantity of available data and the engineering and geological interpretation of that data;

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• estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

• the accuracy of economic assumptions such as the future price of oil and natural gas; and

• the judgment of the personnel preparing the estimates.

SandRidge’s Senior Vice President—Corporate Reservoir Engineering is the technical professional primarily responsible for overseeing the preparation of the Company’s reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering with over 30 years of practical industry experience, including over 30 years of estimating and evaluating reserve information. He has also been a certified professional engineer in the state of Oklahoma since 2007 and a member of the Society of Petroleum Engineers since 1980.

SandRidge’s Reservoir Engineering Department continually monitors asset performance, making reserves estimate adjustments, as necessary, to ensure the most current reservoir information is reflected in reserves estimates. Reserve information includes production histories as well as other geologic, economic, ownership and engineering data. The Corporate Reservoir department currently has a total of 20 full-time employees, comprised of 11 degreed engineers and nine engineering and business analysts with a minimum of a four-year degree in mathematics, finance or other business or science field.

The Company maintains a continuous education program for its engineers and analysts on new technologies and industry advancements and also offers refresher training on basic skill sets.

In order to ensure the reliability of reserves estimates, internal controls within the reserve estimation process include:

• no employee’s compensation is tied to the amount of reserves recorded.

• reserves estimates are prepared by experienced reservoir engineers or under their direct supervision.

• the Senior Vice President—Corporate Reservoir Engineering reports directly to the Company’s Chief Operating Officer.

• the Reservoir Engineering Department follows comprehensive SEC-compliant internal policies to determine and report proved reserves including:

• confirming that reserves estimates include all properties owned and are based upon proper working and net revenue interests;

• reviewing and using in the estimation process data provided by other departments within the Company such as Accounting; and

• comparing and reconciling the Corporate Reservoir department’s internally generated reserves estimates to those prepared by third parties.

Each quarter, the Senior Vice President—Corporate Reservoir Engineering presents the status of the Company’s reserves to a committee of executives, which subsequently approves all changes.

The Reservoir Engineering Department works closely with its independent petroleum consultants at each fiscal year end to ensure the integrity, accuracy and timeliness of annual independent reserves estimates. These independently developed reserves estimates are reviewed by the Audit Committee, as well as the Chief Financial Officer, Senior Vice President of Accounting, Director of Internal Audit, Vice President of Financial Reporting and General Counsel and are approved as the Company’s corporate reserves. In addition to reviewing the independently developed reserve reports, the Audit Committee annually meets with the principal engineers who are primarily responsible for the reserve reports. The Audit Committee also periodically meets with the other independent petroleum consultants that prepare estimates of proved reserves.

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The percentage of the Company’s total proved reserves prepared by each of the independent petroleum consultants is shown in the table below.

	December 31,
	2015		2014		2013
Cawley, Gillespie & Associates, Inc.	77.7	%	82.4	%	64.6	%
Ryder Scott Company, L.P.	8.5	%	—	%	—	%
Netherland, Sewell & Associates, Inc.	3.9	%	3.7	%	21.5	%
Total	90.1	%	86.1	%	86.1	%

The remaining 9.9%, 13.9% and 13.9% of the Company’s estimated proved reserves as of December 31, 2015, 2014 and 2013, respectively, were based on internally prepared estimates.

Copies of the reports issued by the Company’s independent petroleum consultants with respect to the Company’s oil, natural gas and NGL reserves for the substantial majority of all geographic locations as of December 31, 2015 are filed with this report as Exhibits 99.1, 99.2 and 99.3. The geographic location of the Company’s estimated proved reserves prepared by each of the independent petroleum consultants as of December 31, 2015 is presented below.

	Geographic Locations—by Area by State
Cawley, Gillespie & Associates, Inc.	Mid-Continent—KS, OK
Ryder Scott Company, L.P.	Rockies—CO
Netherland, Sewell & Associates, Inc.	Permian Basin—TX

The qualifications of the technical personnel at each of these firms primarily responsible for overseeing the firm’s preparation of the Company’s reserves estimates included in this report are set forth below. These qualifications meet or exceed the Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.

Cawley, Gillespie & Associates, Inc.

• more than 28 years of practical experience in petroleum engineering and more than 26 years of experience estimating and evaluating reserve information;

• a registered professional engineer in the state of Texas; and

• Bachelor of Science Degree in Petroleum Engineering.

Ryder Scott Company, L.P.

• more than 30 years of practical experience in the estimation and evaluation of petroleum reserves;

• a registered professional engineer in the states of Alaska, Colorado, Texas and Wyoming; and

• Bachelor of Science Degree in Petroleum Engineering and MBA in Finance;

Netherland, Sewell & Associates, Inc.

• practicing consulting petroleum engineering since 2013 and over 15 years of prior industry experience;

• licensed professional engineers in the state of Texas; and

• Bachelor of Science Degree in Chemical Engineering

Technologies

Under SEC rules, proved reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence

7

indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil, natural gas or NGLs on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. In determining the amount of proved reserves, the price used must be the average price during the 12-month period prior to the ending date of the period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The estimates of proved developed reserves included in the reserve report were prepared using decline curve analysis to determine the reserves of individual producing wells. After estimating the reserves of each proved developed well, it was determined that a reasonable level of certainty exists with respect to the reserves that can be expected from close offset undeveloped wells in the field.

Development Plan

Based on the economic conditions on December 31, 2015, the Company approved of a plan to develop the proved undeveloped locations identified in the Company’s reserve report within five years of initial booking, in accordance with SEC regulations. The reserve report anticipated a three rig drilling program for the first half of 2016 and four rigs in the second half of the year. Two rigs were scheduled to drill primarily proved undeveloped locations in the first half of 2016, increasing to three rigs in the second half of the year.

However, persistently low commodity prices through the first quarter of 2016 have negatively impacted the Company’s results of operations, financial condition and future development plans. As a result, the Company intends to scale back to a two rig drilling program beginning in the second quarter of 2016. If commodity pricing falls short of the Company’s current expectations or rebounds to a level supportive of more drilling, the Company may change its 2016 capital expenditure plans again. However, the Company’s management does not expect these short term changes to negatively impact the Company’s ability to develop all of its December 31, 2015 proved undeveloped locations within the five year time frame described above, nor does it expect such changes to have a significant impact to the Company’s overall development plan or PV-10 as presented in the Company’s December 31, 2015 reserve report.

Reporting of Natural Gas Liquids

NGLs are produced as a result of the processing of a portion of the Company’s natural gas production stream. At December 31, 2015, NGLs comprised approximately 19% of the Company’s total proved reserves on a barrel equivalent basis

8

and represented volumes to be produced from properties where the Company has contracts in place for the extraction and separate sale of NGLs. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, the Company has included production and reserves in barrels. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs.

9

Reserve Quantities, PV-10 and Standardized Measure

The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2015, 2014 and 2013, the substantial majority of which were prepared by independent petroleum engineers. The estimates include reserves attributable to the Royalty Trusts, including amounts associated with noncontrolling interest. The PV-10 values shown in the table below are not intended to represent the current market value of the Company’s estimated proved reserves as of the dates shown. The reserve reports were based on the Company’s drilling schedule and the average price during the 12-month periods ended December 31, 2015, 2014 and 2013, using first-day-of-the-month prices for each month. Such prices are not reflective of actual prices at December 31, 2015 or current prices. See further discussion of prices in “Risk Factors” included in Item 1A of this report. At December 31, 2015, the Company estimated that approximately 100% of its current proved undeveloped reserves will be developed by the end of 2020. See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.

	December 31,
	2015		2014		2013
Estimated Proved Reserves(1)
Developed
Oil (MMBbls)	48.6		79.0		83.9
NGL (MMBbls)	51.1		56.8		35.8
Natural gas (Bcf)	964.6		1,203.4		951.6
Total proved developed (MMBoe)	260.5		336.4		278.3
Undeveloped
Oil (MMBbls)	29.3		47.0		58.7
NGL (MMBbls)	9.9		35.0		23.3
Natural gas (Bcf)	149.2		584.8		438.8
Total proved undeveloped (MMBoe)	64.1		179.5		155.1
Total Proved
Oil (MMBbls)	77.9		126.0		142.6
NGL (MMBbls)	61.0		91.8		59.1
Natural gas (Bcf)	1,113.8		1,788.2		1,390.4
Total proved (MMBoe)(2)	324.6		515.9		433.4
PV-10 (in millions)(3)	$	1,315.0	$	5,516.4	$	5,191.6
Standardized Measure of Discounted Net Cash Flows (in millions)(2)(4)	$	1,314.6	$	4,087.8	$	4,017.6

____________________

(1) The Company’s estimated proved reserves and the future net revenues, PV-10 and Standardized Measure were determined using prices calculated as a 12-month unweighted average of the first-day-of-the-month index price for each month of each year. All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the Company’s reserve reports are shown in the table below.

	Index prices (a)				Weighted average  wellhead prices (b)
	Oil (per Bbl)		Natural gas (per Mcf)		Oil (per Bbl)(c)		NGL (per Bbl)		Natural gas (per Mcf)
December 31, 2015	$	46.79	$	2.59	$	45.29	$	12.68	$	1.87
December 31, 2014	$	91.48	$	4.35	$	91.65	$	32.79	$	3.61
December 31, 2013	$	93.42	$	3.67	$	95.67	$	31.40	$	3.65

____________________

(a) Index prices are based on average West Texas Intermediate posted prices for oil and average Henry Hub spot market prices for natural gas.

(b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, and regional price differentials.

(c) At December 31, 2013, the weighted average wellhead oil price is significantly higher than the index price as a result of favorable location differentials for production in the Gulf of Mexico.

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(2) Estimated total proved reserves and Standardized Measure include amounts attributable to noncontrolling interests, as shown in the following table:

	Estimated Proved Reserves (MMBoe)	Standardized Measure (In millions)
December 31, 2015	19.1	$	224.6
December 31, 2014	27.6	$	643.3
December 31, 2013	29.9	$	781.6

See “Note 25—Supplemental Information on Oil and Natural Gas Producing Activities” to the Company’s consolidated financial statements in Item 8 of this report for additional information regarding reserve and Standardized Measure amounts attributable to noncontrolling interests.

(3) PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using 12-month average prices for the years ended December 31, 2015, 2014 and 2013. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of the Company’s oil and natural gas properties. PV-10 is used by the industry and by the Company’s management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. It is useful because its calculation is not dependent on the taxpaying status of the entity. The following table provides a reconciliation of the Company’s Standardized Measure to PV-10:

	December 31,
	2015		2014		2013
	(In millions)
Standardized Measure of Discounted Net Cash Flows	$	1,314.6	$	4,087.8	$	4,017.6
Present value of future income tax discounted at 10%	0.4		1,428.6		1,174.0
PV-10	$	1,315.0	$	5,516.4	$	5,191.6

(4) Standardized Measure represents the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions used to calculate PV-10. Standardized Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes.

Proved Reserves - Mid-Continent. Proved reserves in the Mid-Continent, primarily the Mississippian formation, increased from 302.3 MMBoe at December 31, 2013 to 454.4 MMBoe at December 31, 2014 and decreased to 259.1 MMBoe at December 31, 2015. The decrease in 2015 is primarily due to negative pricing revisions of approximately 185 MMBoe, predominantly associated with proved undeveloped reserves, and negative revisions of approximately 29 MMBoe due to well performance. These decreases were partially offset by 45 MMBoe of extensions due to successful drilling in the Mississippian formation. The proved reserves attributable to the Mid-Continent comprise a significant portion of the additions to the Company’s proved reserves for the three-year period. The reserves attributable to more than 1,700 producing wells and continuousness of the formation over the development area further support proved undeveloped classification of selective locations within close proximity to producing wells.

Proved Reserves - Rockies. The Company’s proved reserves in the Rockies, associated with the Niobrara Shale in the North Park Basin of Colorado, were acquired in December 2015 and totaled 27.6 MMBoe at December 31, 2015. The acquisition of these reserves provides an important proved reserve addition to the Company’s asset base. Reservoir characteristics of the Niobrara in the North Park Basin are similar to those of the Niobrara in the DJ Basin to the east of North Park. The reservoir consists of five stacked benches with proved reserves only booked to the D Bench of the Niobrara Shale. Proved developed reserves were booked based on 16 horizontal producing wells drilled in 14 sections across the play. Production performance and reservoir data gathered from the producing wells confirm consistency in reservoir properties such as porosity, thickness and stratigraphic conformity. These wells all encountered proven Niobrara D Bench reserves. Using the performance of the PDP wells, undeveloped reserves were booked for only the D bench of the Niobrara across 27 sections of the proved development area. Although well density in the DJ Basin Niobrara indicates increasing PUD density, the Company has only booked up to four wells per section for only the Niobrara D Bench.

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Proved Reserves - West Texas.In 2015, proved reserves, net of production, decreased by 20.0 MMBoe, primarily due to pricing revisions as a result of significantly lower commodity prices. In 2014, proved reserves decreased by 9 MMBoe, primarily from revisions to proved undeveloped reserves in the Permian Basin, due largely to the removal of proved undeveloped drilling locations not expected to be drilled within a five year period.

Proved Undeveloped Reserves. The following table summarizes activity associated with proved undeveloped reserves during the periods presented:

	Year Ended December 31,
	2015		2014		2013
Reserves converted from proved undeveloped to proved developed (MMBoe)	15.8		31.4		44.6
Drilling capital expended to convert proved undeveloped reserves to proved developed reserves (in millions)	$	117.7	$	343.6	$	437.6

For the year ended December 31, 2015, the Company recognized a decrease in proved undeveloped reserves of 115 MMBoe, primarily due to negative revisions of approximately 147 MMBoe resulting from lower commodity prices. These negative revisions were partially offset by an addition to oil, natural gas and NGL reserves associated with proved undeveloped properties of 48 MMBoe for the year ended December 31, 2015. Reserves added from extensions and discoveries totaled 22 MMBoe, primarily from horizontal drilling in the Mississippian formation in the Mid-Continent, which includes 6 MMBoe of proved undeveloped reserves booked and converted during 2015. Acquisition of the Rockies assets, located in Jackson County, Colorado, in December 2015 added 26 MMBoe of proved undeveloped reserves. Approximately 10 MMBoe of proved undeveloped reserves at December 31, 2014 were converted to proved developed reserves during 2015.

Excluding asset sales, the Company recognized a net addition to oil, natural gas and NGL reserves associated with proved undeveloped properties of 73 MMBoe for the year ended December 31, 2014. Reserves added from extensions and discoveries totaled 67 MMBoe, primarily from horizontal drilling in the Mississippian formation in the Mid-Continent, which includes 10 MMBoe of proved undeveloped reserves booked and converted during 2014. Net positive revisions of 6 MMBoe were recognized and were comprised of 16 MMBoe in increases from the Mid-Continent primarily from an improved overall Mississippian proved undeveloped type curve, partially offset by negative 10 MMBoe revisions primarily from the removal of Permian Basin proved undeveloped drilling locations not expected to be drilled within a five year period. Approximately 21 MMBoe of proved undeveloped reserves at December 31, 2013 were converted to proved developed reserves during 2014.

Excluding asset sales, the Company recognized a net addition to oil, natural gas and NGL reserves associated with proved undeveloped properties of 42 MMBoe for the year ended December 31, 2013. Reserves added from extensions and discoveries totaled 67 MMBoe, primarily from horizontal drilling in the Mississippian formation in the Mid-Continent, which includes 10 MMBoe of proved undeveloped reserves booked and converted during 2013. These additions were offset by downward reserve revisions of 25 MMBoe, primarily from the Mississippian formation, due to the removal of proved undeveloped drilling locations not expected to be drilled within a five year period. These revisions were a result of the Company’s ongoing efforts to optimize its drilling plan within the Mississippian formation and reevaluating anticipated drilling locations. Approximately 35 MMBoe of proved undeveloped reserves at December 31, 2012 were converted to proved developed reserves during 2013.

For additional information regarding changes in the Company’s proved reserves during the three years ended December 31, 2015, 2014 and 2013 see “Note 25—Supplemental Information on Oil and Natural Gas Producing Activities” to the Company’s consolidated financial statements in Item 8 of this report.

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Significant Fields

Oil, natural gas and NGL production for fields containing more than 15% of the Company’s total proved reserves at each year end are presented in the table below. The Mississippi Lime Horizontal field, which is located on the Anadarko Shelf in northern Oklahoma and Kansas and produces from the Mississippian formation, contained more than 15% of the Company’s total proved reserves at December 31, 2015, 2014 and 2013.

	Oil (MBbls)	NGL (MBbls)	Natural Gas (MMcf)	Total (MBoe)
Year Ended December 31, 2015
Mississippi Lime Horizontal	8,041	4,785	77,542	25,750
Year Ended December 31, 2014
Mississippi Lime Horizontal	8,234	3,470	65,839	22,677
Year Ended December 31, 2013
Mississippi Lime Horizontal	6,901	1,311	52,618	16,982

Mississippi Lime Horizontal Field. The Mississippi Lime Horizontal Field is located on the Anadarko Shelf in northern Oklahoma and Kansas and produces from the Mississippian formation. The Company’s interests in the Mississippi Lime Horizontal Field as of December 31, 2015 included 1,773 gross (1,101.7 net) producing wells and a 62% average working interest in the producing area.

Production and Price History

The following tables set forth information regarding the Company’s net oil, natural gas and NGL production and certain price and cost information for each of the periods indicated.

	Year Ended December 31,
	2015		2014		2013
Production Data
Oil (MBbls)	9,600		10,876		14,279
NGL (MBbls)	5,044		3,794		2,291
Natural gas (MMcf)	92,105		85,697		103,233
Total volumes (MBoe)	29,995		28,953		33,776
Average daily total volumes (MBoe/d)	82.2		79.3		92.5
Average Prices(1)
Oil (per Bbl)	$	45.83	$	89.86	$	97.58
NGL (per Bbl)	$	14.36	$	33.41	$	35.16
Natural gas (per Mcf)	$	2.12	$	3.70	$	3.36
Total (per Boe)	$	23.59	$	49.08	$	53.89

____________________

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

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	Year Ended December 31,
	2015		2014		2013
Expenses per Boe
Lease operating expenses
Transportation	$	1.51	$	1.23	$	1.29
Processing, treating and gathering(1)	0.88		1.16		1.05
Other lease operating expenses(2)	7.67		9.27		12.60
Total lease operating expenses	$	10.06	$	11.66	$	14.94
Production taxes(3)	$	0.51	$	1.10	$	0.96
Ad valorem taxes	$	0.23	$	0.29	$	0.35

____________________

(1) Includes costs attributable to gas treatment to remove CO₂ and other impurities from natural gas.

(2) The years ended December 31, 2015, 2014 and 2013 include $34.9 million, $33.9 million and $32.7 million, respectively, for amounts related to the Company’s shortfall in meeting its annual CO₂ delivery obligations under a CO₂ treating agreement as described under “—Properties—West Texas” above.

(3) Net of severance tax refunds.

Productive Wells

The following table sets forth the number of productive wells in which the Company owned a working interest at December 31, 2015. The Company operates substantially all of its wells. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities and natural gas wells awaiting pipeline connections to commence deliveries. Gross wells are the total number of producing wells in which the Company has a working interest and net wells are the sum of the Company’s fractional working interests owned in gross wells.

	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Area
Mid-Continent	1,927	1,191.9	459	200.3	2,386	1,392.2
Rockies	16	16.0	—	—	16	16.0
West Texas	1,212	1,191.4	797	772.1	2,009	1,963.5
Total	3,155	2,399.3	1,256	972.4	4,411	3,371.7

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Drilling Activity

The following table sets forth information with respect to wells the Company completed during the periods indicated. The information presented is not necessarily indicative of future performance, and should not be interpreted to present any correlation between the number of productive wells drilled and quantities or economic value of reserves found. Productive wells are those that produce commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Gross wells refer to the total number of wells in which the Company had a working interest and net wells are the sum of the Company’s fractional working interests owned in gross wells. As of December 31, 2015, the Company had 6 gross (3.8 net) operated wells drilling, completing or awaiting completion.

	2015						2014						2013
	Gross	Percent		Net	Percent		Gross	Percent		Net	Percent		Gross	Percent		Net	Percent
Completed Wells
Development
Productive	167	100.0	%	117.0	100.0	%	626	97.5	%	482.3	97.4	%	607	98.1	%	482.3	98.1	%
Dry	—	—	%	—	—	%	16	2.5	%	13.0	2.6	%	12	1.9	%	9.5	1.9	%
Total	167	100.0	%	117.0	100.0	%	642	100.0	%	495.3	100.0	%	619	100.0	%	491.8	100.0	%
Exploratory
Productive	9	100.0	%	7.0	100.0	%	6	60.0	%	4.6	60.5	%	44	80.0	%	31.0	79.3	%
Dry	—	—	%	—	—	%	4	40.0	%	3.0	39.5	%	11	20.0	%	8.1	20.7	%
Total	9	100.0	%	7.0	100.0	%	10	100.0	%	7.6	100.0	%	55	100.0	%	39.1	100.0	%
Total
Productive	176	100.0	%	124.0	100.0	%	632	96.9	%	486.9	96.8	%	651	96.6	%	513.3	96.7	%
Dry	—	—	%	—	—	%	20	3.1	%	16.0	3.2	%	23	3.4	%	17.6	3.3	%
Total	176	100.0	%	124.0	100.0	%	652	100.0	%	502.9	100.0	%	674	100.0	%	530.9	100.0	%

The following table sets forth information with respect to all rigs operating on the Company’s acreage as of December 31, 2015.

	Owned	Third-Party	Total
Mid-Continent	2	2	4

Developed and Undeveloped Acreage

The following table sets forth information regarding the Company’s developed and undeveloped acreage at December 31, 2015:

	Developed Acreage		Undeveloped Acreage
	Gross	Net	Gross	Net
Area
Mid-Continent	686,600	453,290	1,139,450	819,942
Rockies	28,242	27,476	120,267	107,457
West Texas	54,221	49,681	34,023	18,529
Total	769,063	530,447	1,293,740	945,928

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Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage is established prior to such date, in which event the lease will remain in effect until production has ceased. The following table sets forth as of December 31, 2015, the expiration periods of the gross and net acres that are subject to leases in the undeveloped acreage summarized in the above table.

	Acres Expiring
	Gross	Net
Twelve Months Ending
December 31, 2016	570,696	414,282
December 31, 2017	427,008	322,987
December 31, 2018	64,472	43,022
December 31, 2019 and later	21,477	12,316
Other(1)	210,087	153,321
Total	1,293,740	945,928

____________________

(1) Leases remaining in effect until development efforts or production on the developed portion of the particular lease has ceased.

Included in the acreage due to expire during the twelve months ending December 31, 2016, as presented in the table above, are approximately 556,811 gross (405,648 net) acres in the Mid-Continent area. The Company has options to extend the leases on a portion of this acreage set to expire in the Mid-Continent in 2016 and expects to exercise such options or hold by production portions of such acreage where geological and engineering criteria deem it prudent to do so.

Marketing and Customers

The Company sells oil, natural gas and NGLs to a variety of customers, including utilities, oil and natural gas companies and trading and energy marketing companies. The Company had two customers that individually accounted for more than 10% of its total revenue during 2015. See “Note 23—Business Segment Information” to the Company’s consolidated financial statements in Item 8 of this report for additional information on its major customers. The number of readily available purchasers for the Company’s products makes it unlikely that the loss of a single customer in the areas in which the Company sells its products would materially affect its sales. The Company does not have any material commitments to deliver fixed and determinable quantities of oil and natural gas in the future under existing sales contracts or sales agreements.

Title to Properties

As is customary in the oil and natural gas industry, the Company initially conducts a preliminary review of the title to its properties for which it does not have proved reserves. Prior to the commencement of drilling operations on those properties, the Company conducts a thorough title examination and performs curative work with respect to significant defects. To the extent drilling title opinions or other investigations reflect title defects on those properties, the Company is typically responsible for curing any title defects at its expense. The Company generally will not commence drilling operations on a property until it has cured any material title defects on such property. In addition, prior to completing an acquisition of producing oil and natural gas leases, the Company performs title reviews on the most significant leases, and depending on the materiality of properties, the Company may obtain a drilling title opinion or review previously obtained title opinions. To date, the Company has obtained drilling title opinions on substantially all of its producing properties and believes that it has good and defensible title to its producing properties. The Company’s oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which the Company believes do not materially interfere with the use of, or affect its carrying value of, the properties.

COMPETITION

The Company believes that its leasehold acreage position, midstream assets, geographic concentration of operations and technical and operational capabilities enable it to compete effectively with other exploration and production operations. However, the oil and natural gas industry is intensely competitive.

The Company competes with major oil and natural gas companies and independent oil and natural gas companies for leases, equipment, personnel and markets for the sale of oil, natural gas and NGLs. Many of these competitors are financially stronger than the Company, but even financially troubled competitors can affect the market because of their need to sell oil,

16

natural gas and NGLs at any price to maintain cash flow. Certain companies may be able to pay more for producing properties and undeveloped acreage. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil, natural gas and NGL prices. The Company’s larger or fully integrated competitors may be able to absorb the burden of existing and any future federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position. The Company’s ability to acquire additional properties and to discover reserves in the future depends on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because the Company has fewer financial and human resources than many companies in its industry, the Company may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Oil, natural gas and NGLs compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas and NGLs or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil, natural gas and NGLs.

SEASONAL NATURE OF BUSINESS

Generally, demand for oil and natural gas decreases during the summer months and increases during the winter months. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit the Company’s drilling and producing activities and other oil and natural gas operations in a portion of its operating areas. These seasonal anomalies can pose challenges for meeting the Company’s well drilling objectives, can delay the installation of production facilities, and can increase competition for equipment, supplies and personnel during certain times of the year, which could lead to shortages and increase costs or delay the Company’s operations.

ENVIRONMENTAL REGULATIONS

General

The exploration, development and production of oil and natural gas are subject to stringent federal, state, tribal, regional and local laws and regulations governing worker safety and health, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, which may cause the Company to incur significant capital and operating expenditures or costly actions to achieve and maintain compliance. These laws and regulations may, among other things, require permits to conduct drilling, water withdrawal and other regulated activities; govern the types, quantities and concentrations of substances that may be disposed or released into the environment and the manner of any such disposal or release; limit or prohibit construction or drilling activities or require formal mitigation measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions arising from the Company’s operations or attributable to former operations; impose safety and health restrictions designed to protect employees from exposure to hazardous or dangerous substances; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays or restrictions in permitting or performance of projects and the issuance of orders enjoining operations in affected areas.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus any changes or enhanced enforcement of these laws and regulations that result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements could have a material adverse effect on the Company. Moreover, accidental releases, including spills, may occur in the course of the Company’s operations, and there can be no assurance that the Company will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property and natural resources or personal injury. The Company may be unable to pass on such increased compliance costs to our customers.

The following is a summary of the more significant existing environmental and occupational safety and health laws and regulations, as amended from time to time, applicable to the oil and natural gas industry and for which compliance may have a material adverse impact on the Company.

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Hazardous Substances and Wastes

The Company currently owns, leases, or operates, and in the past has owned, leased, or operated, properties that have been used to explore for and produce oil and natural gas. The Company believes it has utilized operating and disposal practices that were standard in the industry at the applicable time, but hydrocarbons and wastes may have been disposed or released on or under the properties owned, leased, or operated by the Company or on or under other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes were not under the Company’s control. These properties and wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), the federal Resource Conservation and Recovery Act, (“RCRA”) and analogous state laws. Under these laws, the Company could be required to remove or remediate previously disposed wastes, to investigate and clean up contaminated property and to perform remedial operations to prevent future contamination or to pay some or all of the costs of any such action.

CERCLA, also known as the Superfund law, and comparable state laws may impose strict joint and several liability without regard to fault or legality of conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release of a hazardous substance occurred as well as entities that disposed or arranged for the disposal of the hazardous substances released at the site. Under CERCLA, these “responsible persons” may be liable for the costs of cleaning up sites where the hazardous substances have been released, into the environment, for damages to natural resources resulting from the release and for the costs of certain environmental and health studies. Additionally, landowners and other third parties may file claims for personal injury and natural resource and property damage allegedly caused by the release of hazardous substances into the environment. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment from a hazardous substance release and to pursue steps to recover costs incurred for those actions from responsible parties. Certain products used by the Company in the course of its exploration, development and production operations may be regulated as CERCLA hazardous substances. To date, no Company-owned or operated site has been designated as a Superfund site, and the Company has not been identified as a responsible party for any Superfund site.

The Company also generates wastes that are subject to the requirements of RCRA and comparable state statutes. RCRA imposes strict “cradle-to-grave” requirements on the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Drilling fluids, produced waters and other wastes associated with the exploration, production and/or development of crude oil and natural gas are currently excluded from regulation as hazardous wastes under RCRA and, instead, are regulated under RCRA’s less stringent non-hazardous waste requirements. However, it is possible that these wastes could be classified as hazardous wastes in the future. For example, in August 2015, several non-governmental organizations filed notice of intent to sue the EPA under RCRA for, among other things, the agency’s alleged failure to reconsider whether such exclusion should continue to apply. Any change in the exclusion for such wastes could potentially result in an increase in costs to manage and dispose of wastes. In the course of the Company’s operations, it generates petroleum hydrocarbon wastes and ordinary industrial wastes that are subject to regulation under the RCRA. The Company believes it is in substantial compliance with all regulations regarding the handling and disposal of oil and natural gas wastes from its operations.

Air Emissions

The federal Clean Air Act, as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various permitting, monitoring and reporting requirements. These laws and regulations may require the Company to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permit requirements or utilize specific equipment or technologies to control emissions. The need to acquire such permits has the potential to delay or limit the development of oil and natural gas projects. Over the next several years, the Company may be required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in October 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The EPA is required to make attainment and non-attainment designations for specific geographic locations under the revised standards by October 1, 2017. With the EPA lowering the ground-level ozone standard, states may be required to implement more stringent regulations, which could apply to the Company’s operations and result in the need to install new emissions controls, longer permitting timelines and significant increases in the Company’s capital or operating expenditures. Additionally, violations of lease conditions or regulations related to air emissions can result in civil and criminal

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penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.

Water Discharges

The Federal Clean Water Pollution Control Act, also known as the Clean Water Act (the “CWA”), and analogous state laws and implementing regulations, impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States as well as state waters. Pursuant to these laws and regulations, the discharge of pollutants into regulated waters is prohibited unless it is permitted by the EPA or an analogous state agency. The Company does not presently discharge pollutants associated with the exploration, development and production of oil and natural gas into federal or state waters. The CWA including analogous state laws and regulations also impose restrictions and controls regarding the discharge of sediment via storm water run-off to waters of the United States and state waters from a wide variety of construction activities. Such activities are generally prohibited from discharging sediment unless it is permitted by the EPA or an analogous state agency. However, pursuant to the Federal Energy Policy Act of 2005, storm water discharges related to oil and gas exploration, development and production and meeting certain conditions are exempt from the permitting provisions of the CWA. The Company employs certain controls with respect to construction activities to address the discharge of sediment into nearby water bodies. The CWA also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. The EPA issued a final rule in May 2015 that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts consider lawsuits opposing implementation of the rule. To the extent the rule expands the scope of the CWA’s jurisdiction, the Company could incur increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Finally, the Oil Pollution Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and/or CWA include inspection and maintenance programs to minimize spills from oil storage and conveyance systems: the use of secondary containment systems to prevent spills from reaching nearby water bodies; and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The Company has developed and implemented SPCC plans for properties as required under the CWA.

Subsurface Injections

Underground injection operations performed by the Company are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require a permit from the applicable regulatory agencies to operate underground injection wells. Although the Company monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of the Company’s UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property damages and personal injuries. Additionally, some states have considered laws mandating the recycling of flowback and produced water. If such laws are adopted in areas where the Company conducts operations, the Company’s operating costs may increase significantly.

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in Oklahoma, the Oklahoma Corporation Commission (“OCC”) has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging

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back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for wells within areas of interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents. For example, only recently, in January 2016, the OCC ordered five Arbuckle disposal wells within 10 miles of the center of earthquake activity in the Edmond area of Oklahoma to reduce disposal volumes, with wells within 3.5 miles of the activity ordered to reduce disposal volumes by 50 percent while the other wells within 10 miles of the activity were ordered to reduce their disposal volume by 25 percent. In addition, in January 2016, the Governor of Oklahoma announced a grant of $1.38 million in emergency funds to support earthquake research, which research is to be directed by the OCC and the Oklahoma Geological Survey. Further, on February 16, 2016, the OCC issued its largest volume reduction plan to date, covering approximately 5,281 square miles and 245 disposal wells injecting wastewater into the Arbuckle formation. In the plan, the OCC identified 76 SandRidge operated disposals wells, prescribed a four stage volume reduction schedule and set April 30, 2016 as the final date for compliance with the tiered volume reduction plan.

Additionally, the Governor of Kansas has established a task force composed of various administrative agencies to study and develop an action plan for addressing seismic activity in the state. The task force issued a recommended Seismic Action Plan calling for enhanced seismic monitoring and the development of a seismic response plan, and in November 2014, the Governor of Kansas announced a plan to enhance seismic monitoring in the state. In March 2015, the Kansas Corporation Commission issued its Order Reducing Saltwater Injection Rates. The Order identified five areas of heightened seismic concern in Harper and Sumner Counties and created a timeframe over which the maximum of 8,000 barrels of saltwater injection daily into each well. SandRidge and other operators of injection wells, and any injection well drilled deeper than the Arbuckle Formation was required to be plugged back in a manner approved by the Kansas Corporation Commission. On September 14, 2015, the Kansas Corporation Commission extended the Order Reducing Saltwater Injection Rates until March 13, 2016. Most recently, in February 2016, the Kansas Corporation Commission staff recommended an expansion of the areas of heightened seismic concern, which would include an additional schedule of volume reductions for Arbuckle disposal wells not previously identified in the Order released in March 2015.

Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed. The adoption of any new laws, regulations, or directives that restrict the Company’s ability to dispose of saltwater generated by production and development activities , whether by plugging back the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or otherwise, or by requiring SandRidge to shut down disposal wells, could significantly increase SandRidge’s costs to manage and dispose of this saltwater, which could negatively affect the economic lives of the affected properties.

Climate Change

The EPA has published its findings that emissions of CO₂, methane and certain other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emission. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are established by the states. This rule could adversely affect the Company’s operations and restrict or delay its ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds. In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities in the United States on an annual basis. The Company is monitoring and reporting on GHG emissions from certain of its operations upon affected properties.

However, the adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG gases from, the Company’s equipment and operations could require it to incur additional costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas it produces. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level. As a result, a number of

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state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. Any future federal laws or implemented regulations that may be adopted to address GHG emissions could require the Company to incur increased operating costs, adversely affect demand for the oil and natural gas that the Company produces and have a material adverse effect on the Company’s business, financial condition and results of operations. For example, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the international agreement agreed to in Paris. Any such legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for the Company’s oil, natural gas and NGL production, and thus possibly have a material adverse effect on the Company’s revenues.

Endangered or Threatened Species

The Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the federal Migratory Bird Treaty Act. While the Company believes its operations are in substantial compliance with the ESA, exploration and production operations in areas where threatened or endangered species or their habitat are known to exist may require the Company to incur increased costs to implement mitigation or protective measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. If endangered species are located in areas where the Company wishes to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in 2011, the U.S. Fish and Wildlife Service (the “FWS”) is required to consider listing numerous species as endangered under the ESA by the end of the agency’s 2017 fiscal year.

For example, in March 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Oklahoma, Kansas and Texas, where the Company operates, as a threatened species under the ESA. However, on September 1, 2015, the U.S. District Court for the Western District of Texas vacated the FWS’ rule listing the lesser prairie chicken in its entirety, concluding that the decision to list the species was arbitrary and capricious. As a result of the 2014 listing of the lesser prairie chicken, the Company had entered into a range-wide conservation planning agreement, pursuant to which the Company agreed to take measures to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if the Company’s actions harmed the lesser prairie chicken’s habitat. Notwithstanding the 2015 decision by the Western District of Texas Court, the Company has continued its participation in the conservation planning agreement. Whether the lesser prairie chicken or other species will be listed in the future under the ESA is currently unknown but the designation of the lesser prairie chicken or any other previously unprotected species as threatened or endangered in areas where the Company operates could cause the Company to incur increased costs arising from species protection measures or could result in limitations on its exploration and production activities that could have an adverse impact on its ability to develop and produce reserves.

The Company is an active participant on various agency and industry committees that are developing or addressing various EPA and other federal and state agency programs to minimize potential impacts to business activity relating to the protection of any endangered or threatened species.

Employee Health and Safety

The Company’s operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA Hazardous Communication Standard requires that information be maintained concerning hazardous materials used or produced in the Company’s operations and that this information be provided to employees. Pursuant to the Federal Emergency Planning and Community Right-to-Know Act, also known as Title III of the Federal Superfund Amendment and Reauthorization Act, facilities that store threshold amounts of chemicals that are subject to OSHA’s Hazardous Communication Standard above certain threshold quantities must submit information regarding those chemicals by March 1 of each year to state and local authorities in order to facilitate emergency planning and response. That

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information is generally available to the public. The Company believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

State Regulation

The states in which the Company operates, along with some municipalities and Native American tribal areas, regulate some or all of the following activities: the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas. These regulations may affect the number and location of the Company’s wells and the amounts of oil and natural gas that may be produced from the Company’s wells, and increase the costs of the Company’s operations.

Hydraulic Fracturing

Oil and natural gas may be recovered from certain of the Company’s oil and natural gas properties through the use of hydraulic fracturing, combined with sophisticated drilling. Hydraulic fracturing, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and gas commissions. However, several federal agencies have asserted federal regulatory authority over certain aspects of the hydraulic fracturing process. For example, the EPA issued the Clean Air Act final regulations in 2012 and proposed additional Clean Air Act regulations in August 2015 governing performance standards for the oil and natural gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural gas extraction operations must meet before discharging to a treatment plant; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the U.S. Department of the Interior, Bureau of Land Management (“BLM) published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups.

The BLM also proposed new rules in January 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands. The proposal would limit venting and flaring of gas, impose leak detection and repair requirements on wellsite equipment and compressors, and also require the installation of new controls on pneumatic pumps, and other activities at the wellsite such as downhole well maintenance and liquids unloading and drilling workovers and completions to reduce leaks of methane.

Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Oklahoma, have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local government may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at either the state or federal level, the Company’s fracturing activities could become subject to additional permit requirements, reporting requirements or operational restrictions and also to associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that the Company is ultimately able to produce in commercial quantities.

In addition to asserting regulatory authority, certain government reviews are underway that focus on environmental issues associated with hydraulic fracturing practices. For example, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft study,

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indicating its concern that EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur efforts to further regulate hydraulic fracturing.

The Company diligently reviews best practices and industry standards, serves on industry association committees and complies with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources. There have not been any incidents, citations or suits related to the Company’s hydraulic fracturing activities involving environmental concerns.

OTHER REGULATION OF THE OIL AND NATURAL GAS INDUSTRY

The oil and natural gas industry is extensively regulated by numerous federal, state, local, and regional authorities, as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the oil and natural gas industry increases the Company’s cost of doing business and, consequently, affects its profitability, these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.

In July 2014, the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (“PHMSA”) released the details of a comprehensive rulemaking proposal to improve the safe transportation of large quantities of flammable materials by rail, particularly crude oil and ethanol. The Federal Railroad Administration and PHMSA jointly published the final rule on May 1, 2015, and it became effective July 7, 2015.  The final rule (i) contains a new enhanced tank car standard and a risk-based retrofitting schedule for older tank cars carrying crude oil and ethanol; (ii) requires a new braking standard for certain trains; (iii) designates new operational protocols for trains transporting large volumes of flammable liquids, such as routing requirements, speed restrictions, and information for local government agencies; and (iv) provides new sampling and testing requirements to improve classification of energy products placed into transport.

Sales of oil, natural gas and NGLs are not currently regulated and are made at market prices. Although oil, natural gas and NGL prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. The Company cannot predict whether new legislation to regulate oil, natural gas and NGLs might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the Company’s operations.

Drilling and Production

The Company’s operations are subject to various types of regulation at federal, state, local and Native American tribal levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties, municipalities and Native American tribal areas where the Company operates also regulate one or more of the following activities:

• the location of wells;

• the method of drilling and casing wells;

• the timing of construction or drilling activities;

• the rates of production, or “allowables”;

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• the use of surface or subsurface waters;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• the notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company’s interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas the Company can produce from its wells or limit the number of wells or the locations at which the Company can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction.

The Oil Conservation Division of the New Mexico Energy, Minerals and Natural Resources Department requires the posting of financial assurance for owners and operators on privately owned or state land within New Mexico in order to provide for abandonment restoration and remediation of wells. The Railroad Commission of Texas imposes financial assurance requirements on operators. The United States Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.

Natural Gas Sales and Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas the Company produces and the manner in which the Company markets its production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978 have resulted in the removal of all price and non-price controls for sales of domestic natural gas sold in first sales, which include all of the Company’s sales of its own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which the Company may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that the Company produces, as well as the revenues it receives for sales of its natural gas and release of its natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, the Company cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can the Company determine what effect, if any, future regulatory changes might have on the Company’s natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in-state waters. Although its policy is still in flux, in the past FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase the Company’s cost of transporting gas to point-of-sale locations.

Subsurface Injections

Our underground injection operations are subject to the SDWA, as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground Injection Control, or UIC, program, which established the minimum program requirements for state and local programs regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a

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prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require the Company to obtain a permit from the applicable regulatory agencies to operate the Company’s underground injection wells. Although the Company monitors the injection process of its wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of the Company’s UIC permit, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative water supplies, property damages and personal injuries. Additionally, some states, including Texas, have considered laws mandating the recycling of flowback and produced water. If such laws are passed, the Company’s operating costs may increase significantly.

EMPLOYEES

As of December 31, 2015, the Company had 1,165 full-time employees, including 173 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Of the Company’s 1,165 employees, 552 were located at the Company’s headquarters in Oklahoma City, Oklahoma at December 31, 2015, and the remaining employees worked in the Company’s various field offices and drilling sites. The Company completed a reduction in force during the first quarter of 2016, and as of March 2, 2016, had 864 full-time employees, including 153 geologists, geophysicists, petroleum engineers, technicians, land and regulatory professionals. Approximately 369 of the total full-time employees at March 2, 2016, were located at the Company’s headquarters in Oklahoma City, Oklahoma.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of certain oil and natural gas industry terms used in this report.

2-D seismic or 3-D seismic. Geophysical data that depict the subsurface strata in two dimensions or three dimensions, respectively. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D seismic.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Bench. A geological horizon; a thin, distinctive stratum useful for stratigraphic correlation.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. Although an equivalent barrel of condensate or natural gas may be equivalent to a barrel of oil on an energy basis, it is not equivalent on a value basis as there may be a large difference in value between an equivalent barrel and a barrel of oil. For example, based on the commodity prices used to prepare the estimate of the Company’s reserves at year-end 2015 of $46.79/Bbl for oil and $2.59/Mcf for natural gas, the ratio of economic value of oil to gas was approximately 18 to 1, even though the ratio for determining energy equivalency is 6 to 1.

Boe/d. Boe per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

CO₂. Carbon dioxide.

Developed acreage. The number of acres that are assignable to productive wells.

Developed oil, natural gas and NGL reserves. Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (ii) drill and equip development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry well. An exploratory, development or extension well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Environmental Assessment (“EA”). A study to determine whether an action significantly affects the environment, which federal or state agencies may be required by the National Environmental Policy Act or similar state statutes to undertake prior to the commencement of activities that would constitute federal or state actions, such as permitting oil and natural gas exploration and production activities.

Environmental Impact Statement. A more detailed study of the environmental effects of an undertaking and its alternatives than an EA, which may be required by the National Environmental Policy Act or similar state statutes, either after the EA has been prepared and determined that the environmental consequences of a proposed federal undertaking, such as permitting oil and natural gas exploration and production activities, may be significant, or without the initial preparation of an EA if a federal or state agency anticipates that a proposed undertaking may significantly impact the environment.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to produce oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls. Thousand barrels of oil or other liquid hydrocarbons.

MBoe. Thousand barrels of oil equivalent.

Mcf. Thousand cubic feet of natural gas.

MMBbls. Million barrels of oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. MMcf per day.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

NGL. Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

NYMEX. The New York Mercantile Exchange.

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Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Present value of future net revenues (“PV-10”). The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities, that become part of the cost of oil and gas produced.

Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Prospect. A specific geographic area that, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Reserves that are both proved and developed.

Proved oil, natural gas and NGL reserves. Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which defines proved reserves as:

Those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves. Reserves that are both proved and undeveloped.

Pulling units. Pulling units are used in connection with completions and workover operations.

PV-10. See “Present value of future net revenues” above.

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Rental tools. A variety of rental tools and equipment, ranging from trash trailers to blowout preventers to sand separators, for use in the oilfield.

Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market, and all permits and financing required to implement the project.

Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Roustabout services. The provision of manpower to assist in conducting oilfield operations.

Standardized measure or standardized measure of discounted future net cash flows. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes on future net revenues.

Trucking. The provision of trucks to move the Company’s drilling rigs from one well location to another and to deliver water and equipment to the field.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

Undeveloped oil, natural gas and NGL reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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Item 1A.    Risk Factors

The Company has engaged advisors to assist with a private restructuring or reorganization under Title 11 of the U.S. Bankruptcy Code in the foreseeable future, which raises substantial doubt about its ability to continue as a going concern.

As a result of the impacts to the Company’s financial position resulting from declining industry conditions and in consideration of the substantial amount of long-term debt outstanding, the Company has engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its financial position or complete any strategic transactions. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern as it is currently structured.

As a result, the report of the Company’s independent registered public accounting firm that accompanies these consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern, which under the terms of the Company’s senior secured revolving credit facility (“senior credit facility”) may result in an event of default. If the Company does not obtain a waiver of this requirement or otherwise cure this event within 30 calendar days of the issuance of these financial statements, the lenders under the senior credit facility will be able to accelerate maturity of the debt. Any acceleration of the obligations under the senior credit facility would result in a cross-default and potential acceleration of the maturity of the Company’s other outstanding long-term debt. These defaults create additional uncertainty associated with the Company’s ability to repay its outstanding long-term debt obligations as they become due and further reinforces the substantial doubt over the Company’s ability to continue as a going concern.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect the Company’s business, financial condition or results of operations.

Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit. Furthermore, even if sufficient amounts of oil or natural gas exist, the Company may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. Decisions to develop properties depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The estimated cost of drilling, completing and operating wells is uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. In addition, the Company’s drilling and producing operations may be curtailed, delayed or canceled as a result of various factors, including the following:

• reductions in oil, natural gas and NGL prices;

• delays imposed by or resulting from compliance with regulatory requirements including permitting;

• unusual or unexpected geological formations and miscalculations;

• shortages of or delays in obtaining equipment and qualified personnel;

• shortages of or delays in obtaining water for hydraulic fracturing operations;

• equipment malfunctions, failures or accidents;

• lack of available gathering facilities or delays in construction of gathering facilities;

• lack of available capacity on interconnecting transmission pipelines;

• lack of adequate electrical infrastructure and water disposal capacity;

• unexpected operational events and drilling conditions;

• pipe or cement failures and casing collapses;

• pressures, fires, blowouts and explosions;

• lost or damaged drilling and service tools;

• loss of drilling fluid circulation;

• uncontrollable flows of oil, natural gas, brine, water or drilling fluids;

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• natural disasters;

• environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

• high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing;

• compliance with environmental and other governmental requirements;

• adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes;

• oil and natural gas property title problems; and

• market limitations for oil, natural gas and NGLs.

Certain of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties.

Oil, natural gas and NGL prices can fluctuate widely due to a number of factors that are beyond the Company’s control. Continued depressed or further declining oil, natural gas or NGL prices could significantly affect the Company’s financial condition and results of operations.

The Company’s revenues, profitability and cash flow are highly dependent upon the prices it realizes from the sale of oil, natural gas and NGLs. The markets for these commodities are very volatile and have experienced significant decline during the latter half of 2014, throughout 2015, and into 2016. Oil, natural gas and NGL prices can move quickly and fluctuate widely in response to a variety of factors that are beyond the Company’s control. These factors include, among others:

• changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGLs, as well as perceptions of supply of, and demand for, oil, natural gas and NGLs generally;

• the price and quantity of foreign imports;

• the ability of other companies to complete and commission liquefied natural gas export facilities in the U.S.;

• U.S. and worldwide political and economic conditions;

• weather conditions and seasonal trends;

• anticipated future prices of oil, natural gas and NGLs, alternative fuels and other commodities;

• technological advances affecting energy consumption and energy supply;

• the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;

• natural disasters and other extraordinary events;

• domestic and foreign governmental regulations and taxation;

• energy conservation and environmental measures; and

• the price and availability of alternative fuels.

For oil, from January 2011 through December 2015, the highest month end NYMEX settled price was $113.93 per Bbl and the lowest was $37.04 per Bbl. For natural gas, from January 2011 through December 2015, the highest month end NYMEX settled price was $5.56 per MMBtu and the lowest was $2.03 per MMBtu. In addition, the market price of oil and natural gas is generally higher in the winter months than during other months of the year due to increased demand for oil and natural gas for heating purposes during the winter season.

Oil prices dropped sharply during the latter half of 2014 and have continued to decline throughout 2015 and into 2016, and settled as low as $26.21 per Bbl in February 2016. Continued low oil, natural gas or NGL prices will decrease the Company’s cash flows and revenues, and also may ultimately reduce the amount of oil, natural gas and NGLs that it can produce economically, causing the Company to make substantial downward adjustments to its estimated proved reserves and having a material adverse effect on its financial condition and results of operations.

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Unless the Company replaces its oil, natural gas and NGL reserves, its reserves and production will decline, which would adversely affect the Company’s business, financial condition and results of operations.

             The Company's future oil, natural gas and NGL reserves and production, and therefore its cash flow and income, are highly dependent on its success in efficiently developing and exploiting its current reserves and finding or acquiring additional economically recoverable reserves. Declining cash flows from operations, as a result of lower commodity prices, could require the Company to reduce expenditures to develop and acquire additional reserves. Further, the Company may not be able to develop, find or acquire additional reserves to replace its current and future production at acceptable costs, which could adversely affect its business, financial condition and results of operations.

Future price declines may result in reductions of the asset carrying values of the Company’s oil and natural gas properties.

The Company utilizes the full cost method of accounting for costs related to its oil and natural gas properties. Under this accounting method, all costs for both productive and nonproductive properties are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. However, the amount of these costs that can be carried as capitalized assets is subject to a ceiling, which limits such pooled costs to the aggregate of the present value of future net revenues of proved oil, natural gas and NGL reserves attributable to proved properties, discounted at 10%, plus the lower of cost or market value of unevaluated properties. The full cost ceiling is evaluated at the end of each quarter using the most recent 12-month average prices for oil and natural gas, adjusted for the impact of derivatives accounted for as cash flow hedges. The Company incurred a full cost ceiling impairment charge of $4.5 billion for the year ended December 31, 2015, and had cumulative full cost ceiling impairment charges of $8.2 billion and $3.7 billion at December 31, 2015 and 2014, respectively. The Company incurred a full cost ceiling impairment charge of $164.8 million for the year ended December 31, 2014, and had no full cost ceiling impairment during the year ended December 31, 2013. If oil, natural gas and NGL prices fail to recover significantly in the near term, and without other mitigating circumstances, the Company will experience additional losses of future net revenues, including losses attributable to quantities that cannot be economically produced at lower prices, which would likely cause the Company to record additional write-downs of capitalized costs of its oil and natural gas properties and non-cash charges against future earnings. The amount of such future write-downs and non-cash charges could be substantial. Further, the borrowing base under the senior credit facility is calculated by reference to the value of the Company’s oil and natural gas reserves, as determined by the lenders under the senior credit facility, and declines in the value of such reserves as a result of sustained low commodity prices resulted in a reduction to the borrowing base in March 2016 and could further reduce the amount available to be borrowed by the Company under its senior credit facility if prices decline further from current levels.

The Company has a substantial amount of indebtedness and other obligations and commitments, which may adversely affect its cash flow and its ability to operate its business.

As of December 31, 2015, the Company’s total indebtedness was $3.6 billion and the Company had preferred stock outstanding with an aggregate liquidation preference of $542.0 million. The Company’s substantial level of indebtedness and the dividends associated with its outstanding preferred stock increases the possibility that it may be unable to generate cash sufficient to pay, when due, the principal of, interest on or other amounts due in respect of the Company’s indebtedness and/or the preferred stock dividends. Declining cash flows from operations, as a result of declines in oil and natural gas prices, may increase the Company’s borrowing needs under its senior credit facility to fund working capital. The Company’s indebtedness and outstanding preferred stock, combined with its lease and other financial obligations and contractual commitments, could have other important consequences to the Company. For example, it could:

• make the Company more vulnerable to adverse changes in general economic, industry and competitive conditions and adverse changes in government regulation;

• require the Company to dedicate an even greater portion of its cash flow from operations to payments on its indebtedness, thereby reducing the availability of the Company’s cash flows to fund working capital, capital expenditures, acquisitions and other general corporate purposes;

• require the Company to finance an increasing portion of its working capital and capital expenditures with cash on hand and borrowing under its senior credit facility;

• limit the Company’s flexibility in planning for, or reacting to, changes in its business and the industry in which it operates;

• place the Company at a disadvantage compared to its competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that the Company’s indebtedness prevents it from pursuing; and

• limit the Company’s ability to borrow additional amounts for working capital, capital expenditures, acquisitions, debt service requirements, execution of its business strategy or other purposes.

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Any of the above listed factors could have a material adverse effect on the Company’s business, financial condition and results of operations.

The Company’s estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of the Company’s reserves. The Company’s current estimates of reserves could change, potentially in material amounts, in the future.

The process of estimating oil, natural gas and NGL reserves is complex and inherently imprecise, requiring interpretations of available technical data and many assumptions, including assumptions relating to production rates and economic factors such as historic oil and natural gas prices, drilling and operating expenses, capital expenditures, the assumed effect of governmental regulation and availability of funds for development expenditures. Inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of the Company’s reserves. See “Business—Business Segments and Primary Operations” in Item 1 of this report for information about the Company’s oil, natural gas and NGL reserves.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas and NGL reserves will vary and could vary significantly from the Company’s estimates shown in this report, which in turn could have a negative effect on the value of the Company’s assets. In addition, from time to time in the future, the Company will adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development, changes in oil, natural gas and NGL prices and other factors, many of which are beyond the Company’s control.

The present value of future net cash flows from the Company’s proved reserves calculated in accordance with SEC guidelinesare not the same as the current market value of its estimated oil, natural gas and NGL reserves.

The Company bases the estimated discounted future net cash flows from its proved reserves on 12-month average index prices and costs, as is required by SEC rules and regulations. Commodity prices have remained depressed and have at times trended lower. Accordingly, if the Company had prepared its December 31, 2015 reserve reports based on the updated 12-month average index prices (which were $42.77 and $2.40 through March 1, 2016) instead of the 12-month average index prices (which were $46.79 and $2.59), and without regard to additions or other further revisions to reserves other than as a result of such pricing changes, the PV-10 value of its internally estimated proved reserves would have decreased by approximately $229.0 million. Actual future net cash flows from the Company’s oil and natural gas properties will be affected by actual prices the Company receives for oil, natural gas and NGLs, as well as other factors such as:

• the accuracy of the Company’s reserve estimates;

• the actual cost of development and production expenditures;

• the amount and timing of actual production;

• supply of and demand for oil, natural gas and NGLs; and

• changes in governmental regulation or taxation.

The timing of both the Company’s production and its incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the Company uses a 10% discount factor when calculating discounted future net cash flows, which may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.

The Company will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible.

The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive or may suffer from declining production faster than anticipated. The use of seismic data and other technologies and the study of producing fields in the same area do not enable the Company to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. During 2015, the Company completed a total of 176 gross wells, none of which were identified as dry wells. If the Company drills additional wells that it identifies as dry wells in its current and future prospects, its drilling success rate may decline and materially harm its business.

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Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather.

Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather. Repercussions of natural disasters or severe weather conditions may include:

• evacuation of personnel and curtailment of operations;

• damage to drilling rigs or other facilities, resulting in suspension of operations;

• inability to deliver materials to worksites; and

• damage to, or shutting in of, pipelines and other transportation facilities.

In addition, the Company’s hydraulic fracturing operations require significant quantities of water. Regions in which the Company operates have recently experienced drought conditions. Any diminished access to water for use in hydraulic fracturing, whether due to usage restrictions or drought or other weather conditions, could curtail the Company’s operations or otherwise result in delays in operations or increased costs.

The capital markets could be volatile, and such volatility could adversely affect the Company’s ability to obtain capital, cause it to incur additional financing expense or affect the value of certain assets.

During and following the recent global financial crisis, financial and capital markets were volatile due to multiple factors, including significant losses in the financial services sector and uncertain and rapidly changing economic conditions both in the U.S. and globally. In some cases, financial markets produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial and/or operating strength. Volatility in the capital markets can significantly increase the cost of raising money in the debt and equity capital markets. Future market volatility, generally, and persistent weakness in commodity prices may adversely affect the Company’s ability to access capital and credit markets or to obtain funds at low interest rates or on other advantageous terms. These factors may adversely affect the Company’s business, results of operations or liquidity.

These factors may also adversely affect the value of certain of the Company’s assets and its ability to draw on its senior credit facility. Adverse credit and capital market conditions may require the Company to reduce the carrying value of assets associated with derivative contracts to account for non-performance by, or increased credit risk from, counterparties to those contracts. If financial institutions that have extended credit commitments to the Company are adversely affected by volatile conditions of the U.S. and international capital markets, they may become unable to fund borrowings under their credit commitments to the Company, which could have a material adverse effect on its financial condition and its ability to borrow additional funds, if needed, for working capital, capital expenditures and other corporate purposes.

Properties acquired by the Company may not produce as projected, and the Company may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

The Company’s initial technical reviews of properties it acquires are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well and environmental problems, such as soil or ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the Company may assume certain environmental and other risks and liabilities in connection with acquired properties, and such risks and liabilities could have a material adverse effect on its results of operations and financial condition.

The development of the Company’s proved undeveloped reserves may take longer and may require higher levels of capital expenditures than the Company currently anticipates.

As of December 31, 2015, approximately 19.7% of the Company’s total reserves were proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than the Company currently anticipates. Therefore, recoveries from these fields may not match current expectations. Delays in the development of the Company’s reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of the Company’s estimated proved undeveloped reserves and future net revenues estimated for such reserves.

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A significant portion of the Company’s operations are located in the Mid-Continent region, making it vulnerable to risks associated with operating in a limited number of major geographic areas.

As of December 31, 2015, approximately 79.8% of the Company’s proved reserves and approximately 88.5% of its annual production was located in the Mid-Continent. This concentration could disproportionately expose the Company to operational and regulatory risk in these areas. This relative lack of diversification in location of its key operations could expose the Company to adverse developments in these areas or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production due to weather, electrical outages, treatment plant closures for scheduled maintenance or other factors. These factors could have a significantly greater impact on the Company’s financial condition, results of operations and cash flows than if the Company’s properties were more diversified.

The Company’s development and exploration operations require substantial capital, and the Company may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in the Company’s oil, natural gas and NGL reserves.

The oil and natural gas industry is capital intensive. The Company makes substantial capital expenditures in its business and operations for the exploration, development, production and acquisition of oil, natural gas and NGL reserves. Historically, the Company has financed capital expenditures primarily with proceeds from asset sales and from the sale of equity and debt securities and cash generated by operations. In particular, the Company had cash flow from operations of $373.5 million, $621.1 million and $868.6 million, for the years ended December 31, 2015, 2014 and 2013, respectively. However, as a result of sustained depressed commodity prices, the capital markets that the Company has historically accessed are currently constrained to such an extent that debt or equity capital raises are practically unfeasible. If the debt and equity capital markets do not improve, the Company may be unable to implement its drilling and development plans or otherwise carry out its business strategy as expected. The Company’s cash flow from operations and access to capital are subject to a number of variables, including:

• the prices at which oil, natural gas and NGLs are sold;

• the Company’s proved reserves;

• the level of oil, natural gas and NGLs it is able to produce from existing wells;

• the Company’s ability to acquire, locate and produce new reserves; and

• the Company’s capital and operating costs.

Oil prices fell sharply in the latter half of 2014 and have continued to decline throughout 2015 and into 2016, and continued low prices will reduce the Company’s revenues and cash flow from operations. Reductions in the Company’s revenues and cash flow from operations, whether as a result of lower oil, natural gas and NGL prices, lower production, declines in reserves or for any other reason, may limit the Company’s ability to obtain the capital necessary to sustain its operations at desired levels. In order to fund capital expenditures, the Company may seek additional financing. However, the Company’s senior credit facility contains covenants limiting its ability to incur additional indebtedness, and the Company’s lenders may withhold their consent to exceed the limitations in such covenants at their sole discretion. The Company’s senior note indentures also contain covenants that may restrict the Company’s ability to incur additional indebtedness if it does not satisfy certain financial metrics. The Company significantly lowered its capital expenditures plan for 2015 due, in part, to sustained low commodity prices. If prices remain at low levels and the Company is unable to obtain additional financing, it may be necessary for the Company to further reduce or even suspend its capital expenditures.

Disruptions in the global financial and capital markets also could adversely affect the Company’s ability to obtain debt or equity financing on favorable terms, or at all. The failure to obtain additional financing could result in a curtailment of the Company’s operations relating to exploration and development of its prospects, which in turn could lead to a possible loss of properties and a decline in the Company’s oil, natural gas and NGL reserves.

The agreements governing the Company’s existing indebtedness have restrictions, financial covenants and borrowing base redeterminations, which could adversely affect its operations.

The Company’s senior credit facility and the indentures governing its senior notes restrict the Company’s ability to, among other things, obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. The senior credit facility also requires the Company to comply with certain financial covenants and ratios. See additional discussion of the senior credit agreement amendment under “Cash Flows-Senior Credit Facility.” Persistent depressed oil or natural gas prices or further decline in such prices, without other mitigating circumstances, could prevent the Company from complying with the financial covenants under its amended senior credit facility. The Company’s failure to comply with any of the restrictions and covenants under the senior credit facility, senior notes or other debt financings could result in a default under those instruments, which, if left uncured, could lead to an event of default. Such an event of default could, among other things, result in all of its

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existing indebtedness to be immediately due and payable. Additionally, an event of default under one of the Company’s financing instruments could trigger cross-default provisions under the Company’s other financing instruments. The application of the remedies under the financing instruments could have a material adverse effect on the Company’s financial position.

The Company’s senior credit facility limits the amounts it can borrow to a borrowing base amount. The borrowing base is subject to review semi-annually; however, the lenders reserve the right to have one additional redetermination of the borrowing base per calendar year. Unscheduled redeterminations may be made at the Company’s request, but are limited to two requests per year. Borrowing base determinations are based upon proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves. Outstanding borrowings exceeding the borrowing base must be repaid promptly, or the Company must pledge other oil and natural gas properties as additional collateral. The Company may not have the financial resources in the future to make any mandatory principal prepayments under the senior credit facility, which are required, for example, when the committed line of credit is exceeded, proceeds of asset sales in new oil and natural gas properties are not reinvested, or indebtedness that is not permitted by the terms of the senior credit facility is incurred. If the indebtedness under the Company’s senior credit facility and senior notes were to be accelerated, the Company’s assets may not be sufficient to repay such indebtedness in full.

On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties.

The Company’s derivative activities could result in financial losses and reduce earnings.

To achieve a more predictable cash flow and to reduce its exposure to adverse fluctuations in the prices of oil and natural gas, the Company currently has entered, and may in the future enter, into derivative contracts for a portion of its future oil and natural gas production, including fixed price swaps, collars and basis swaps. The Company has not designated and does not plan to designate any of its derivative contracts as hedges for accounting purposes and, as a result, records all derivative contracts on its balance sheet at fair value with changes in the fair value recognized in current period earnings. Accordingly, the Company’s earnings may fluctuate significantly as a result of changes in the fair value of its derivative contracts. Derivative contracts also expose the Company to the risk of financial loss in some circumstances, including when:

• production is less than expected;

• the counterparty to the derivative contract defaults on its contract obligations; or

• the actual differential between the underlying price in the derivative contract and actual prices received is materially different from that expected.

In addition, these types of derivative contracts can limit the benefit the Company would receive from increases in the prices for oil and natural gas.

The Company’s services revenues depend on the needs of other companies in the oil and natural gas industry.

Companies to which the Company provides oilfield services are affected by the oil and natural gas industry risks mentioned above. Market prices of oil, natural gas and NGLs, limited access to capital and reductions in capital expenditures could result in oil and natural gas companies canceling or curtailing their drilling programs, which could reduce the demand for the Company’s oilfield services. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil, natural gas and NGL prices or otherwise, could impact the Company’s oilfield services segment by negatively affecting revenues, cash flow and profitability;

Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which the Company may not be adequately insured.

There are a variety of operating risks inherent in oil, natural gas and NGL production and associated activities, such as fires, leaks, explosions, mechanical problems, major equipment failures, blowouts, uncontrollable flow of oil, natural gas and NGLs, water or drilling fluids, casing collapses, abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or permanently halt the production and sale of oil, natural gas and NGLs at any of the Company’s properties could have a material adverse impact on its business activities, financial condition and results of operations.

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Additionally, if any of such risks or similar accidents occur, the Company could incur substantial losses as a result of injury or loss of life, severe damage or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and clean-up responsibility. If the Company experiences any of these problems, its ability to conduct operations could be adversely affected. While the Company maintains insurance coverage that it deems appropriate for these risks, its operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance.

Shortages or increases in costs of equipment, services and qualified personnel could adversely affect the Company’s ability to execute its exploration and development plans on a timely basis and within its budget.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Additionally, higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly affect the Company’s ability to execute its exploration and development plans as projected.

Market conditions or operational impediments may hinder the Company’s access to oil, natural gas and NGL markets or delay production of oil, natural gas and NGLs.

Market conditions or a lack of satisfactory oil and natural gas transportation arrangements may hinder the Company’s access to oil, natural gas and NGL markets or delay production of oil, natural gas and NGLs. The availability of a ready market for the Company’s oil, natural gas and NGL production depends on a number of factors, including the demand for and supply of oil, natural gas and NGLs and the proximity of reserves to pipelines and terminal facilities. The Company’s ability to market its production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and treating facilities for oil, natural gas and NGLs as well as gathering systems, treating facilities and disposal wells for water produced alongside the hydrocarbons. The Company’s failure to obtain such services on acceptable terms in the future or to expand its midstream assets could have a material adverse effect on its business. The Company may be required to shut in wells for a lack of a market or because access to natural gas pipelines, gathering system capacity, treating facilities or disposal wells may be limited or unavailable. The Company would be unable to realize revenue from any shut-in wells until production arrangements were made to deliver the production to market.

Competition in the oil and natural gas industry is intense, which may adversely affect the Company’s ability to succeed.

The oil and natural gas industry is intensely competitive, and the Company competes with many companies that have greater financial and other resources than it does. Many of these companies not only explore for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or identify, evaluate, bid for and purchase a greater number of properties and prospects than the Company’s financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. The Company’s larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than it can, which would adversely affect its competitive position.

The Company’s use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas. In addition, the use of such technology requires greater predrilling expenditures, which could adversely affect the results of the Company’s drilling operations.

A significant aspect of the Company’s exploration and development plan involves seismic data. Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are present in those structures. Other geologists and petroleum professionals, when studying the same seismic data, may have significantly different interpretations than the Company’s professionals. The Company’s drilling activities may not be geologically successful or economical, and its overall drilling success rate or its drilling success rate for activities in a particular area may not improve as a result of using 2-D and 3-D seismic data.

The use of 2-D and 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and the Company could incur losses due to such expenditures. In addition, the Company may often gather 2-D and 3-D seismic data over large areas. The Company’s interpretation of seismic data delineates for it those portions of an area that it believes are desirable for drilling. Therefore, the Company may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, the Company may identify hydrocarbon indicators before seeking option or lease rights in the location. If the Company is not able to lease those locations on acceptable terms, it will have made substantial expenditures to acquire and analyze 2-D and 3-D seismic data without having an opportunity to attempt to benefit from those expenditures.

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The Company is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting its operations or expose it to significant liabilities.

The Company’s oil and natural gas exploration, production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, the Company must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. The Company may incur substantial costs in order to maintain compliance with these laws and regulations. As well as recent incidents involving the release of oil and natural gas and fluids as a result of drilling activities in the United States, there have been a variety of regulatory initiatives at the federal and state levels to restrict oil and natural gas drilling operations in certain locations. Any increased regulation or suspension of oil and natural gas exploration and production, or revision or reinterpretation of existing laws and regulations, that arises out of these incidents or otherwise could result in delays and higher operating costs. Such costs or significant delays could have a material adverse effect on the Company’s business, financial condition and results of operations. The Company must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the Company is a shipper on interstate pipelines, it must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity.

Laws and regulations governing oil and natural gas exploration and production may also affect production levels. The Company is required to comply with federal and state laws and regulations governing conservation matters, including provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; and the plugging and abandonment of wells. These and other laws and regulations can limit the amount of oil and natural gas the Company can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations.

New laws or regulations, or changes to existing laws or regulations, may unfavorably impact the Company, could result in increased operating costs and could have a material adverse effect on the Company’s financial condition and results of operations. For example, Congress has recently considered, and may continue to consider, legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, and the elimination of certain U.S. federal tax preferences available with respect to oil and natural gas exploration and production activities. In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and rules promulgated thereunder could reduce trading positions in the energy futures or swaps markets and materially reduce hedging opportunities for the Company, which could adversely affect its revenues and cash flows during periods of low commodity prices, and which could adversely affect the Company’s ability to restructure its hedges when it might be desirable to do so.

Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may increase capital costs for the Company and third-party downstream oil and natural gas transporters. These and other potential regulations could increase the Company’s operating costs, reduce its liquidity, delay its operations, increase direct and third-party post production costs or otherwise alter the way the Company conducts its business, which could have a material adverse effect on its financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid by the Company for transportation on downstream interstate pipelines.

The Company’s operations are subject to environmental and occupational safety and health laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations or result in significant costs and liabilities.

The Company’s oil and natural gas exploration and production operations are subject to stringent federal, state, tribal, regional and local laws and regulations governing worker safety and health, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to operations, including the acquisition of permits to conduct drilling and the performance of other regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the imposition of safety and health regulations designed to protect employees from exposure to hazardous substances; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. Failure to comply with these laws and regulations may result in litigation; the assessment of sanctions, including administrative, civil or criminal penalties; the imposition of investigatory, remedial or corrective action obligations; the occurrence of delays or restrictions in permitting or performance of projects; and the issuance of injunctions limiting or preventing some or all of the Company’s operations in affected areas.

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There is inherent risk of incurring significant environmental costs and liabilities in the performance of the Company’s operations due to its handling of petroleum hydrocarbons and wastes, because of air emissions and wastewater discharges related to its operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the Company could be subject to strict, joint and several strict liability for the investigation, removal or remediation of previously released materials or property contamination regardless of whether it was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which the Company’s wells are drilled and facilities where its petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for contamination even in the absence of non-compliance, with environmental laws and regulations or for personal injury, natural resources damage or property damage.

In addition, the risk of accidental spills or releases could expose the Company to significant liabilities that could have a material adverse effect on the Company’s financial condition or results of operations. Certain laws related to oil spills impose strict, joint and several strict liability, without regard to fault, for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by those laws, they are limited. If an oil discharge or substantial threat of discharge were to occur, the Company may be liable for costs and damages, which costs and damages could be material to its results of operations and financial position.

Changes in environmental laws and regulations occur frequently, and any changes that result delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport, remediation or disposal, emission or discharge requirements could require significant expenditures by the Company to attain and maintain compliance and may otherwise have a material adverse effect on its results of operations, competitive position or financial condition. For example, in October 2015, the EPA issued a final rule under the Clean Air Act, lowering the NAAQS for ground-level ozone to 70 parts per billion under both the primary and secondary standards to provide requisite protection of public health and welfare, respectively. The Company may not be able to recover some or any of these costs from insurance. As a result of any increased cost of compliance, the Company may decide to discontinue drilling.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays and adversely affect the Company’s production.

Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in the majority of its drilling and completion programs. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA issued Clean Air Act final regulations in 2012 and proposed additional Clean Air Act regulations in August 2015 governing performance standards for the oil and natural gas industry; proposed in April 2015 effluent limitations guidelines that waste water from shale natural gas extraction operations must meet before discharging to a treatment plant; and issued in 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands but, in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups. The BLM also proposed new rules in January 2016 which seek to limit methane emissions from new and existing oil and gas operations on federal lands. The proposal would limit venting and flaring of gas, impose leak detection and repair requirements on wellsite equipment and compressors, and also require the installation of new controls on pneumatic pumps, and other activities at the wellsite such as downhole well maintenance and liquids unloading and drilling workovers and completions to reduce leaks of methane. From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition, certain states, including Oklahoma, have adopted regulations that could impose new or more stringent permitting, disclosure, and well-construction requirements on hydraulic-fracturing operations. States could elect to prohibit hydraulic fracturing altogether, following the approach of the State of New York in 2015. Also, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. If new laws or regulations that significantly restrict or regulate hydraulic fracturing are adopted at the local, state or federal level, fracturing activities with respect to the Company’s properties could become subject to additional permit requirements, reporting requirements or operational restrictions and also to associated permitting delays and potential increases in costs. These delays or additional costs could adversely affect the determination of whether a well is commercially viable. Restrictions on hydraulic fracturing could also reduce the amount of oil, NGL or natural gas that is ultimately produced in commercial quantities from the Company’s properties.

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In addition to asserting regulatory authority, certain government reviews are underway that focus on environmental issues associated with hydraulic fracturing practices. For example, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA released its draft report on the potential impacts of hydraulic fracturing on drinking water resources in June 2015, which report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA’s Science Advisory Board provided its comments on the draft study, indicating its concern that EPA’s conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

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

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

Furthermore, in response to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in Oklahoma, the OCC has implemented a variety of measures including adopting the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. The OCC also evaluates existing wells to assess their continued operation, or operation with restrictions, based on location relative to such faults, seismicity and other factors, with certain of such existing wells required to make frequent, or even daily, volume and pressure reports. In addition, the OCC has rules requiring operators of certain saltwater disposal wells in the state to, among other things, conduct mechanical integrity testing or make certain demonstrations of such wells’ depth that, depending on the depth, could require the plugging back of such wells and/or the reduction of volumes disposed in such wells. As a result of these measures, the OCC from time to time has developed and implemented plans calling for wells within Areas of Interest where seismic incidents have occurred to restrict or suspend disposal well operations in an attempt to mitigate the occurrence of such incidents. For example, only recently, in January 2016, the OCC ordered five Arbuckle disposal wells within 10 miles of the center of earthquake activity in the Edmond area of Oklahoma to reduce disposal volumes, with wells within 3.5 miles of the activity to reduce their disposal volumes by 50 percent while the other wells within 10 miles of the activity to reduce their disposal volume by 25 percent. In addition, in January 2016, the Governor of Oklahoma announced a grant of $1.38 million in emergency funds to support earthquake research, which research is to be directed by the OCC and the Oklahoma Geological Survey. Further, on February 16, 2016, the OCC issued its largest volume reduction plan to date, covering approximately 5,281 square miles and 245 disposal wells injecting wastewater into the Arbuckle formation. In the plan, the OCC identified 76 SandRidge operated disposals wells, prescribed a four stage volume reduction schedule and set April 30, 2016 as the final date for compliance with the tiered volume reduction plan.

Additionally, the Governor of Kansas has established a task force composed of various administrative agencies to study and develop an action plan for addressing seismic activity in the state. The task force issued a recommended Seismic Action Plan calling for enhanced seismic monitoring and the development of a seismic response plan, and in November 2014, the Governor of Kansas announced a plan to enhance seismic monitoring in the state. In March 2015, the Kansas Corporation Commission issued its Order Reducing Saltwater Injection Rates. The Order identified five areas of heightened seismic concern in Harper and Sumner Counties and created a timeframe over which the maximum of 8,000 barrels of saltwater injection daily into each well. The Company and other operators of injection wells, and any injection well drilled deeper than the Arbuckle Formation was required to be plugged back in a manner approved by the Kansas Corporation Commission. On September 14, 2015, the Kansas Corporation Commission extended the Order Reducing Saltwater Injection Rates until March 13, 2016. Most recently, in February 2016, the Kansas Corporation Commission staff recommended an expansion of the areas of heightened seismic concern, which would include an additional schedule of volume reductions for Arbuckle disposal wells not previously identified in the Order released in March 2015.

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Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed. The adoption of any new laws, regulations, or directives that restrict the Company’s ability to dispose of saltwater generated by production and development activities, whether by plugging back the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or otherwise, or by requiring the Company to shut down disposal wells, which could negatively affect the economic lives of the Company’s properties.

The adoption and implementation of any new laws, regulations or legal directives that restrict the Company’s ability to dispose of saltwater, by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring the Company to shut down disposal wells, could require the Company or the operators of wells in which the Company has interests to shut in a substantial number of such wells and, accordingly, could materially and adversely affect the Company’s business, financial condition and results of operations, and could have a material adverse effect on the Trust.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that the Company produces while the physical effects of climate change could disrupt the Company’s production and cause the Company to incur significant costs in preparing for or responding to those effects.

The EPA has published its findings that emissions of GHGs present a danger to public health and the environment because such gases are contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted rules that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards.

In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities in the United States on an annual basis. However, the adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, the Company’s equipment and operations could require it to incur additional costs to monitor, report and potentially reduce emissions of GHGs associated with its operations or could adversely affect demand for the oil and natural gas that it produces. Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could have a material adverse effect on the Company’s assets and operations, and potentially subject the Company to greater regulation.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level. As a result, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The adoption of any legislation or regulations imposing reporting obligations on, or limiting emissions of GHGs from, equipment and operations could require costs to be incurred by the Company to reduce emissions of GHGs associated with operations or could adversely affect demand for the oil, natural gas and NGL that the Company produces and have a material adverse effect on the Company’s business, financial condition and results of operations. For example, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. It is not possible at this time to predict how or when the United State might impose restrictions on GHGs as a result of the international agreement agreed to in Paris. Any such legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for the oil, natural gas and NGL produced from the Company. The Company, consistent with its obligation to act as a reasonably prudent operator, may abandon a well that is uneconomic or not generating revenues from production in excess of its operating costs.

Repercussions from terrorist activities or armed conflict could harm the Company’s business.

Terrorist activities, anti-terrorist efforts or other armed conflict involving the United States or its interests abroad may adversely affect the United States and global economies and could prevent the Company from meeting its financial and other obligations. If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a

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reduction in the Company’s revenues. Oil and natural gas production facilities, transportation systems and storage facilities could be direct targets of terrorist attacks, and/or operations could be adversely impacted if infrastructure integral to the Company’s operations is destroyed by such an attack. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

The Company’s failure to maintain an adequate system of internal control over financial reporting, could adversely affect its ability to accurately report its results.

Management is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles. A material weakness is a deficiency, or a combination of deficiencies, in the Company’s internal control over financial reporting that results in a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. Effective internal controls are necessary for the Company to provide reliable financial reports and deter and detect any material fraud. If the Company cannot provide reliable financial reports or prevent material fraud, its reputation and operating results would be harmed. The Company maintained effective internal control over financial reporting as of December 31, 2015, as further described in Item 9A—Controls and Procedures and Management’s Report on Internal Control over Financial Reporting. The Company’s efforts to develop and maintain its internal controls and to remediate material weaknesses in its controls may not be successful, and it may be unable to maintain adequate controls over its financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation, including those related to acquired businesses, or other effective improvement of the Company’s internal controls could harm its operating results. Ineffective internal controls could also cause investors to lose confidence in the Company’s reported financial information.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

The Obama administration’s budget proposals in recent years, including the budget proposal for fiscal year 2017, have included provisions eliminating certain key U.S. federal income tax preferences currently available to companies involved in oil and natural gas exploration and production. If enacted into law, these provisions would repeal certain incentives and credits applicable to taxpayers engaged in the exploration or production of oil and natural gas. These provisions include, but are not limited to (i) the repeal of current expensing of intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties, (iii) the repeal of domestic manufacturing deduction for oil and natural gas production and (iv) the increase in the amortization period from two years to seven years for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil and natural gas within the United States. It is unclear whether any similar provisions will be included in future budget proposals, whether such provisions will actually be enacted or how soon any such provisions would become effective if enacted. The passage of any legislation relating to such proposals or any other similar changes in U.S. federal income tax laws could negatively affect the Company’s financial condition and results of operations.

New derivatives legislation and regulation could adversely affect the Company’s ability to hedge risks associated with its business.

The Dodd-Frank Act created a new regulatory framework for oversight of derivatives transactions by the Commodity Futures Trading Commission (the “CFTC”) and the SEC. Among other things, the Dodd-Frank Act subjects certain swap participants to new capital, margin and business conduct standards. In addition, the Dodd-Frank Act contemplates that where appropriate in light of outstanding exposures, trading liquidity and other factors, swaps (broadly defined to include most hedging instruments other than futures) will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility, unless the “end-user” exception from clearing applies. The Dodd-Frank Act also established a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets and also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into for bona fide hedging purposes).

There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. However, although the Company may qualify for exceptions, its derivatives counterparties may be subject to new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act, which may increase the Company’s transaction costs or make it more difficult for the Company to enter into hedging transactions on favorable terms. The Company’s inability to enter into hedging transactions on favorable terms, or at all, could increase its operating expenses and put it at increased exposure to risks of adverse changes in oil and natural gas prices, which could adversely affect the predictability of cash flows from sales of oil and natural gas.

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In November 2011, the CFTC finalized rules to establish a position limits regime on certain “core” physical-delivery contracts and their economically equivalent derivatives, some of which reference major energy commodities, including oil and natural gas. However, in September 2012, the District Court of the District of Columbia vacated the CFTC’s rulemaking and remanded to the CFTC for further proceedings. On November 6, 2013, the CFTC re-proposed rules to establish a position limits regime on 28 “core” physical commodity contracts and their “economically equivalent” futures, options, and swaps, some of which reference major energy commodities, including oil and natural gas (“Position Limits Re-Proposal”), as well as amending the rules governing the aggregation of positions. Notably, the Position Limits Re-Proposal provides limited enumerated hedge exemptions from the position limits and a prescriptive process for requiring an exemption for non-enumerated hedges. The most recent comment period for the Position Limits Re-Proposal closed on January 22, 2015, but the final rules related to position limits are not yet in effect. To the extent the Position Limits Re-Proposal is finalized, such regulations could subject the Company or its derivatives counterparties to limits on commodity positions and thereby have an adverse effect on its ability to hedge risks associated with its business or on the cost of its hedging activity. 

Cyber-attacks or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of the Company’s business operations.

In recent years, the Company has increasingly relied on information technology systems and networks in connection with its business activities, including certain of its exploration, development and production activities. The Company relies on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil and gas reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. These threats pose a risk to the security of the Company’s systems and networks, the confidentiality, availability and integrity of its data and the physical security of its employees and assets. The Company has experienced, and expects to continue to confront, attempts from hackers and other third parties to gain unauthorized access to its information technology systems and networks. Although prior cyber-attacks have not had a material adverse impact on the Company’s operations or financial performance, there can be no assurance that the Company will be successful in preventing cyber-attacks or successfully mitigating their effect. Any cyber-attack could have a material adverse effect on the Company’s reputation, competitive position, business, financial condition and results of operations. Cyber-attacks or security breaches also could result in litigation or regulatory action, as well as significant additional expense to implement further data protection measures.

In addition to the risks presented to the Company’s systems and networks, cyber-attacks affecting oil and gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack of this nature would be outside the Company’s ability to control, but could have a material, adverse effect on the Company’s business, financial condition and results of operations.

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Item 1B.    Unresolved Staff Comments

None.

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Item 2.        Properties

Information regarding the Company’s properties is included in Item 1.

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Item 3.        Legal Proceedings

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

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

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

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

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

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

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

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

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

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

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

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

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

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

On October 7, 2015, the derivative plaintiffs in the Federal Shareholder Derivative Litigation, the SLC, and the individual defendants in the Federal Shareholder Derivative Litigation (Tom Ward, Jim Brewer, Everett Dobson, William Gilliland, Daniel Jordan, Roy Oliver Jr., and Jeffrey Serota), executed a Stipulation of Settlement, which would result in a partial settlement of the Federal Shareholder Derivative Litigation by settling all claims against the individual defendants, subject to certain terms and conditions, including the approval of the court. Under the terms of the proposed partial settlement, the Company would implement or agree to maintain certain corporate governance reforms, and the insurers for the individual defendants would pay $38.0 million to an escrow fund, which would be used to pay certain expenses arising from pending securities litigation and, to the extent funds remain after paying such expenses, would be paid to the Company without any further restrictions on the Company’s use of such funds. The proposed partial settlement expressly provides, among other terms, that the settling defendants deny all allegations of wrongdoing and are entering into the settlement solely to avoid the costs, disruption, uncertainty, and risk of further litigation.

On October 9, 2015, the court issued an Order granting preliminary approval of the Stipulation of Settlement and, after notice and a hearing on December 18, 2015, the court issued a Final Judgment and Order on December 22, 2015, granting final approval of the Stipulation of Settlement. The partial settlement did not settle any of the derivative plaintiffs’ claims against non-settling defendants WCT Resources, L.L.C., 192 Investments, L.L.C., and TLW Land & Cattle, L.P in the Federal Shareholder Derivative Litigation. On January 12, 2016, a shareholder who objected to the Stipulation of Settlement filed a notice of appeal of the court’s Final Judgment and Order approving the Stipulation of Settlement.

On November 30, 2015, the court stayed the Hefner action until further order of the court. An estimate of reasonably possible losses associated with the Hefner action cannot be made at this time. The Company has not established any reserves relating to this action.

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

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of the Mississippian Trust II in or traceable to its initial public offering on or about April 23, 2012. The claims are based on allegations that the Company, certain of its current and former officers and directors, and the Mississippian Trusts, among other defendants, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and natural gas reserves, the Company’s capital expenditures, and certain transactions entered into by companies allegedly affiliated with the Company’s former CEO Tom Ward.

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

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

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

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

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

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

On May 27, 2015, the parties reached an agreement in principle to settle this lawsuit. Pursuant to such agreement, the Company will establish a settlement fund from which to pay participating plaintiffs’ claims as well as plaintiffs’ attorneys’ fees. The proposed settlement agreement is subject to final negotiations between the parties and court approval. During the year ended December 31, 2015, the Company established a $5.1 million reserve for this lawsuit.

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

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

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

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

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

On November 24, 2015, the plaintiffs filed a Consolidated Class Action Complaint in the consolidated Gernandt action. The Company intends to defend this consolidated lawsuit vigorously. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

On November 18, 2015, Mickey Peck, on behalf of himself and others similarly situated, filed a First Amended Collective Action Complaint in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc., and

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SandRidge Operating Company for violations of the Fair Labor Standards Act. Plaintiff alleges that the Company improperly classified certain of its consultants as independent contractors rather than as employees and, therefore, improperly paid such consultants a day rate without paying any overtime compensation. On January 14, 2016, the Court entered an Order conditionally certifying the class and providing for notice. 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 January 12, 2016, Lisa Griggs and April Marler, on behalf of themselves and all other similarly situated, filed a putative class action petition in the District Court of Logan County, Oklahoma, against SandRidge Exploration and Production, LLC, and certain other oil and gas exploration companies. In their petition, plaintiffs assert various tort claims based upon purported damage and loss resulting from earthquakes allegedly caused by the defendants’ operations of wastewater disposal wells. Plaintiffs seek to certify a class of “all residents of Oklahoma owning real property from 2011 through the time the Class is certified.” On February 16, 2016, the defendants filed a Notice of Removal of the lawsuit to the United States District Court for the Western District of Oklahoma. 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 February 12, 2016, Brenda Lene and Jon Darryn Lene filed a petition in the District Court of Logan County, Oklahoma, against SandRidge Exploration and Production, LLC, and certain other oil and gas exploration companies. In their petition, plaintiffs assert various tort claims based on their allegations that their home suffered damages due to earthquakes allegedly caused by the defendants’ operations of wastewater disposal wells. 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 March 3, 2016, Brian Thieme, on behalf of himself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that, commencing on or around December 27, 2007, and continuing until at least March 31, 2012, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties containing producing oil and natural gas wells located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Sections 1 and 3 of the Sherman Antitrust Act. Plaintiff seeks to certify two separate and distinct classes of members. 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 March 10, 2016, Don Beadles, in Trust for the Alva Synagogue Church, on behalf of himself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that since as early as December 2007, and continuing until at least as late as March 2012 (the “Relevant Class Period”), the defendants conspired to rig bids and otherwise depress the amounts they paid to property owners for the acquisition of oil and gas leasehold interests and producing properties located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Sections 1 and 3 of the Sherman Antitrust Act. Plaintiff seeks to certify a class of “all persons and entities that, during the Relevant Class Period, provided or sold to one of more of the Defendants (a) oil and gas leasehold interests on their property and/or (b) the producing properties, in exchange for lease payments, including but not limited to lease bonuses.” 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 March 24, 2016, Janet L. Lowry, on behalf of herself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that, commencing on or around December 27, 2007, and continuing until at least March 31, 2012, the defendants conspired to rig bids and depress the price of royalty and bonus payments exchanged for purchases of oil and natural gas leasehold interests and interests in properties containing producing oil and natural gas wells located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Section 1 of the Sherman Antitrust Act. Plaintiff seeks to certify two separate and distinct classes of members. 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.

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On February 4, 2015, the staff of the SEC Enforcement Division in Washington, D.C., notified the Company that it had commenced an informal inquiry concerning the Company’s accounting for, and disclosure of, its carbon dioxide delivery shortfall penalties under the terms of the Gas Treating and CO2 Delivery Agreement, dated June 29, 2008, between SandRidge Exploration and Production, LLC, and Oxy USA Inc.

Additionally, the Company received a letter from an attorney for a former employee at the Company (the “Former Employee”).  In the letter, the attorney alleged, among other things, that the Former Employee had been terminated because he had objected to the levels of oil and gas reserves disclosed by the Company in its public filings.  Over 85% of such reserves were calculated by an independent petroleum engineering firm.  The Audit Committee of the Company’s Board of Directors has retained an independent law firm to review the Former Employee’s allegations and the circumstances of the Former Employee’s termination.  In addition, the Company reported the Former Employee’s allegations to the SEC staff, which thereafter issued two subpoenas to the Company relating to the Former Employee’s allegations.  Counsel for the Audit Committee is responding to both of these subpoenas.

During the course of the above inquiries, the SEC issued a subpoena to the Company seeking documents relating to employment-related agreements between the Company and certain employees. The Company is cooperating with this inquiry and, after discussion with staff, the Company sent corrective letters to certain current and former employees who had entered into agreements containing language that may have been inconsistent with SEC rules prohibiting a company from impeding an individual from communicating directly with the SEC about possible securities law violations. The Company also updated its Code of Conduct and other relevant policies.

The Company continues to cooperate with the above inquiries and is unable to predict their outcome or the possible loss, if any, that could result from their potential resolution.

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.

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Item 4.        Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

PRICE RANGE OF COMMON STOCK

Through December 31, 2015, the Company’s common stock was listed on the New York Stock Exchange (“NYSE”) under the symbol “SD.” The range of high and low sales prices for its common stock for the periods indicated, as reported by the NYSE, is as follows:

	High		Low
2015
Fourth Quarter	$	0.56	$	0.17
Third Quarter	$	0.90	$	0.25
Second Quarter	$	2.30	$	0.81
First Quarter	$	2.53	$	1.13
2014
Fourth Quarter	$	4.80	$	1.50
Third Quarter	$	7.20	$	4.10
Second Quarter	$	7.43	$	6.07
First Quarter	$	6.75	$	5.59

On March 23, 2016, there were 285 record holders of the Company’s common stock.

The Company has neither declared nor paid any cash dividends on its common stock, and it does not anticipate declaring any dividends on its common stock in the foreseeable future. The Company expects to retain cash for the operation and expansion of its business, including exploration, development and production activities. In addition, the terms of the Company’s indebtedness restrict its ability to pay dividends to holders of its common stock. Accordingly, if the Company’s dividend policy were to change in the future, its ability to pay dividends would be subject to these restrictions and the Company’s then-existing conditions, including its results of operations, financial condition, contractual obligations, capital requirements, business prospects and other factors deemed relevant by its Board of Directors.

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PERFORMANCE GRAPH

The following graph compares the cumulative total return to stockholders on SandRidge common stock relative to the cumulative total returns of the S&P Oil and Gas Exploration and Production Index and the S&P 500 Index from January 1, 2011 through December 31, 2015. The graph assumes that the value of the investment in the Company’s common stock and in each of the indexes was $100.00 on January 1, 2011.

The performance graph above is furnished and not filed for purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any registration statement filed under the Securities Act unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.

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ISSUER PURCHASES OF EQUITY SECURITIES

The following table presents a summary of share repurchases made by the Company during the three-month period ended December 31, 2015.

	Total Number of Shares Purchased(1)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Maximum  Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (In millions)
Period
October 1, 2015 — October 31, 2015	153,376	$	0.50	N/A	N/A
November 1, 2015 — November 30, 2015	9,568	$	0.37	N/A	N/A
December 1, 2015 — December 31, 2015	10,307	$	0.17	N/A	N/A
Total	173,251			—

____________________

(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.

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Item 6.        Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, the Company’s selected financial information. The Company’s financial information is derived from its audited consolidated financial statements for such periods. The financial data includes the results of the Company’s acquisitions and divestitures, including PGC and the Rockies properties in the fourth quarter of 2015, the divestiture of the Gulf Properties in February 2014, the divestiture of the Permian Properties in February 2013, the acquisition of oil and natural gas properties in the Gulf of Mexico in June 2012, and the acquisition of oil and natural gas properties in the Gulf of Mexico from Dynamic Offshore Resources LLC in April 2012. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the Company’s consolidated financial statements and notes thereto contained in “Financial Statements and Supplementary Data” in Item 8 of this report. The following information is not necessarily indicative of the Company’s future results.

	Year Ended December 31,
	2015			2014			2013			2012			2011
	(In thousands, except per share data)
Statement of Operations Data
Revenues	$	768,709		$	1,558,758		$	1,983,388		$	1,934,642		$	1,415,213
Expenses
Production	308,701			346,088			516,427			477,154			322,877
Production taxes	15,440			31,731			32,292			47,210			46,069
Cost of sales	24,394			56,155			57,118			68,227			65,654
Midstream and marketing	26,819			49,905			53,644			39,669			66,007
Construction contract	—			—			23,349			—			—
Depreciation and depletion—oil and natural gas	319,913			434,295			567,732			568,029			317,246
Depreciation and amortization—other	47,382			59,636			62,136			60,805			53,630
Accretion of asset retirement obligations	4,477			9,092			36,777			28,996			9,368
Impairment	4,534,689			192,768			26,280			316,004			2,825
General and administrative(1)	150,166			122,865			330,425			241,682			148,643
(Gain) loss on derivative contracts	(73,061		)	(334,011		)	47,123			(241,419		)	(44,075		)
Loss on settlement of contract	50,976			—			—			—			—
Loss (gain) on sale of assets	1,491			10			399,086			3,089			(2,044		)
Total expenses	5,411,387			968,534			2,152,389			1,609,446			986,200
(Loss) income from operations	(4,642,678		)	590,224			(169,001		)	325,196			429,013
Other (expense) income
Interest expense	(321,421		)	(244,109		)	(270,234		)	(303,349		)	(237,332		)
Bargain purchase gain	—			—			—			122,696			—
Gain (loss) on extinguishment of debt	641,131			—			(82,005		)	(3,075		)	(38,232		)
Other income, net	2,040			3,490			12,445			4,741			3,122
Total other expense	321,750			(240,619		)	(339,794		)	(178,987		)	(272,442		)
(Loss) income before income taxes	(4,320,928		)	349,605			(508,795		)	146,209			156,571
Income tax expense (benefit)	123			(2,293		)	5,684			(100,362		)	(5,817		)
Net (loss) income	(4,321,051		)	351,898			(514,479		)	246,571			162,388
Less: net (loss) income attributable to noncontrolling interest	(623,506		)	98,613			39,410			105,000			54,323
Net (loss) income attributable to SandRidge Energy, Inc.	(3,697,545		)	253,285			(553,889		)	141,571			108,065
Preferred stock dividends	37,950			50,025			55,525			55,525			55,583
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(3,735,495	)	$	203,260		$	(609,414	)	$	86,046		$	52,482
(Loss) earnings per share
Basic	$	(7.16	)	$	0.42		$	(1.27	)	$	0.19		$	0.13
Diluted	$	(7.16	)	$	0.42		$	(1.27	)	$	0.19		$	0.13
Weighted average number of common shares outstanding
Basic	521,936			479,644			481,148			453,595			398,851
Diluted	521,936			499,743			481,148			456,015			406,645

____________________

(1) Includes employee termination benefits.

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	As of December 31,
	2015			2014		2013		2012		2011
	(In thousands)
Balance Sheet Data
Cash and cash equivalents	$	435,588		$	181,253	$	814,663	$	309,766	$	207,681
Property, plant and equipment, net	$	2,234,702		$	6,215,057	$	6,307,675	$	8,479,977	$	5,389,424
Total assets	$	2,991,155		$	7,259,225	$	7,684,795	$	9,790,731	$	6,219,609
Total debt	$	3,631,506		$	3,195,436	$	3,194,907	$	4,301,083	$	2,814,176
Total stockholders’ (deficit) equity	$	(1,187,733	)	$	3,209,820	$	3,175,627	$	3,862,455	$	2,548,950
Total liabilities and stockholders’ (deficit) equity	$	2,991,155		$	7,259,225	$	7,684,795	$	9,790,731	$	6,219,609

There have been no cash dividends declared or paid on the Company’s common stock.

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Item 7.        Management’s Discussion and Analysis of Financial Condition and Results of Operations

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 other sections of this report, including: “Business” in Item 1, “Selected Financial Data” in Item 6 and “Financial Statements and Supplementary Data” in Item 8. The Company’s discussion and analysis includes the following subjects:

• Overview;

• Results by Segment;

• Consolidated Results of Operations;

• Liquidity and Capital Resources;

• Valuation Allowance; and

• Critical Accounting Policies and Estimates.

Overview

SandRidge Energy, Inc. is an energy company with principal operations in the Mid-Continent region in Oklahoma and Kansas. At December 31, 2015, the Company also owned properties in the Rockies in Colorado, which were acquired during the fourth quarter of 2015, and in west Texas. The Company sold the majority of its Gulf Properties in 2014 and its Permian Basin assets in 2013 and has used the proceeds from those transactions to reduce outstanding long-term debt and fund drilling and development in its core area of focus. See further discussion of these transactions 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 and disposal system and an electrical transmission system. Additionally, until January 2016, the Company operated a drilling and related oilfield services business.

Recent Events

Senior Credit Facility. During January 2016, the Company borrowed the available capacity under the senior credit facility, or $488.9 million, and such amounts remained outstanding at March 23, 2016. On March 11, 2016, the administrative agent of the senior credit facility notified the Company that the lenders had elected to reduce the borrowing base to $340.0 million pursuant to a special redetermination. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties.

Divestiture of WTO Properties and Release from Treating Agreement. On January 21, 2016, the Company paid $11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the WTO, including the PGC assets acquired in October 2015, to Occidental and was released from all past, current and future claims and obligations under an existing 30-year treating agreement between the companies. As of December 31, 2015, the Company had accrued approximately $109.9 million for penalties associated with shortfalls in meeting its delivery requirements under the agreement since it became effective in late 2012, including $34.9 million incurred for the year ended December 31, 2015.

Production, proved reserves, revenues and direct operating expenses for the oil and natural gas properties transferred in the transaction were 1.9 MMBoe, 24.6 MMBoe, $14.6 million and $41.1 million, respectively, as of and for the year ended December 31, 2015.

Acquisition of Piñon Gathering Company, LLC. In October 2015, the Company acquired the assets of and terminated a gas gathering agreement with PGC for $48.0 million cash and $78.0 million principal amount of Senior Secured Notes. PGC’s assets consist of approximately 370 miles ofgathering lines that support the Company’s production in the Piñon field in West Texas. The transaction resulted in the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. The fair value of the consideration paid by the Company, including discount attributable to the Senior Secured Notes issued, was approximately $98.3 million and was

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allocated on a relative fair value basis between the assets acquired (approximately $47.3 million) and a loss on the termination of the gathering contract (approximately $51.0 million).

Acquisition of Rockies Properties. In December 2015, the Company acquired approximately 135,000 net acres in the North Park Basin, Jackson County, Colorado for approximately $191.1 million in cash, including post-closing adjustments. Also included in the acquisition were working interests in 16 wells previously drilled on the acreage. Additionally, the seller paid the Company $3.1 million for certain overriding interests retained in the properties. The Company commenced development of the acquired acreage in early 2016.

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

Repurchase, Exchange and Redemption of Senior Unsecured Notes. In August 2015, the Company repurchased approximately $250.0 million of its 8.75% Senior Notes due 2020, 7.5% Senior Notes due 2021, 8.125% Senior Notes due 2022, and 7.5% Senior Notes due 2023 (collectively, “Senior Unsecured Notes”) for approximately $94.5 million cash and issued $275.0 million aggregate principal amount of 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, “Convertible Senior Unsecured Notes”) in exchange for $275.0 million aggregate principal amount of its Senior Unsecured Notes. In October 2015, the Company repurchased $100.0 million of its Senior Unsecured Notes for approximately $30.0 million cash, and issued $300.0 million aggregate principal amount of Convertible Senior Unsecured Notes in exchange for $300.0 million aggregate principal amount of its Senior Unsecured Notes. Through December 31, 2015, holders of the Company’s Convertible Senior Unsecured Notes have redeemed approximately $255.3 million in aggregate principal amount ($73.7 million net of discount and including holders’ conversion feature liabilities) of the Convertible Senior Unsecured Notes for approximately 92.8 million shares of the Company’s common stock. The repurchases and exchanges of the Company’s Senior Unsecured Notes and subsequent redemptions of the Company’s Convertible Senior Unsecured Notes resulted in an aggregate gain on extinguishment of debt of approximately $623.2 million.

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

2014 and 2013 Divestitures

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% overriding royalty interest in certain exploration prospects. The Company used 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 the Company making cash payments of approximately $69.6 million. This transaction did not result in a significant alteration of the relationship between the Company’s capitalized costs and proved reserves and, accordingly, the Company recorded the proceeds as a reduction of its full cost pool with no gain or loss on the sale.

Production, revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties included in the Company’s results for the years ended December 31, 2014, and 2013 were as follows:

	Year Ended December 31,
	2014(1)		2013
Production (MBoe)	1,321		10,082
Revenues (in thousands)	$	90,920	$	627,236
Expenses (in thousands)	$	63,674	$	491,991

_______________

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

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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 in “Liquidity and Capital Resources,” 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, 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 were as follows as of and for the year ended December 31, 2013: 

	Year Ended December 31,
	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.

2015 Operational Activities

Operational highlights for 2015 include the following:

• Total production for 2015 was comprised of approximately 32.0% oil, 51.2% natural gas and 16.8% NGLs compared to 37.6% oil, 49.3% natural gas and 13.1% NGLs in 2014.

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

• Drilled 161 wells, excluding salt water disposal wells, in the Mid-Continent area. Mid-Continent properties contributed approximately 26.6 MMBoe, or 88.5%, of the Company’s total production in 2015 compared to approximately 23.4 MMBoe, or 80.9%, in 2014.

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

Outlook

The Company established a 2016 capital expenditures budget of approximately $285.0 million, with approximately $262.0 million designated for exploration and production activities. These amounts reflect a decrease from total 2015 capital expenditures of 59% and a decrease from 2015 exploration and production capital expenditures of 60%.

The Company’s estimated proved reserve volumes were 324.6 MMBoe at December 31, 2015 based on internal estimates using the SEC-mandated historical 12-month unweighted average pricing at such date, which were $46.79 per barrel of oil and $2.59 per Mcf of natural gas. Replacing the January 1, 2015, February 1, 2015 and March 1, 2015 price components with actual January 1, 2016, February 1, 2016 and March 1, 2016 benchmark commodities prices, the 12-month unweighted average prices would have been $42.77 per barrel of oil and $2.40 per Mcf of natural gas. If the Company’s December 31, 2015 reserves estimates were made using the reduced 12-month average prices, and without regard to additions or other further revisions to reserves other than as a result of such pricing changes, the Company’s internally estimated proved reserves as of December 31, 2015 would decrease by approximately 6%, and PV-10 would decrease by approximately $229.0 million, primarily as a result of the loss of proved undeveloped locations. As a result of continued depressed commodity prices, the Company’s final capital plan for 2016, developed in March 2016, contemplates a smaller drilling program than that assumed in the development of the December 31, 2015 reserve report. If commodity pricing falls short of the Company’s current expectations or rebounds to a level supportive of more drilling, the Company may change its 2016 capital expenditure plans again. However, the Company’s management does not expect these short term changes to negatively impact the Company’s ability to develop all of its December 31, 2015 proved undeveloped locations within a five year time frame. All reserve estimates for periods after December 31, 2015 provided in this Form 10-K were determined by Company reservoir engineers and, accordingly, have not been fully assessed by independent petroleum consultants.

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In light of impacts to the Company’s financial position resulting from declining industry conditions and the Company’s leverage position, the Company has engaged advisors to assist with the evaluation of strategic alternatives and has engaged in discussion with certain stakeholders regarding strategic alternatives to restructure its indebtedness. The Company is also focused on cost reductions, including the identification of non-core assets for potential sale. There can be no assurance that any restructuringtransaction will occur as a result of such discussions with stakeholders, that the terms of any potential restructuring transaction or other transactions would be acceptable to the Company or that such transactions would be successful. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern as it is currently structured.

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Results by Segment

During the years ended December 31, 2015, 2014 and 2013 the Company operated in three reportable business segments: exploration and production, drilling and oilfield services and midstream services, each of which offer 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 oilfield services segment, which was substantially discontinued during January 2016, was engaged in the contract drilling of oil and natural gas wells and provided various oilfield 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. Results for the Company’s business segments for the years ended December 31, 2015, 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 and economically develop and produce its reserves. The primary factors affecting the financial results of the Company’s exploration and production segment are the quantity of oil, natural gas and NGLs it produces, the prices the Company receives for its production and changes in the fair value of its commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. To provide information on the general trend in pricing, the average annual NYMEX prices for oil and natural gas for recent years are presented in the table below: 

	Year Ended December 31,
	2015		2014		2013		2012		2011
Oil (per Bbl)	$	48.75	$	92.91	$	98.05	$	94.15	$	95.11
Natural gas (per Mcf)	$	2.62	$	4.26	$	3.73	$	2.83	$	4.03

In order to reduce the Company’s exposure to price fluctuations, the Company historically has entered into commodity derivative contracts for a portion of its anticipated future oil and natural gas production as discussed in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.” Reducing the Company’s exposure to price volatility helps mitigate the risk that it will not have adequate funds available for its capital expenditure programs.

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Set forth in the table below is financial, production and pricing information for the exploration and production segment for the years ended December 31, 2015, 2014 and 2013.

	Year Ended December 31,
	2015			2014			2013
Results (in thousands)
Revenues
Oil	$	439,927		$	977,269		$	1,393,360
NGL	72,440			126,759			80,555
Natural gas	195,067			316,851			346,363
Other	12			2,194			14,202
Inter-segment revenue	(12		)	(173		)	(320		)
Total revenues	707,434			1,422,900			1,834,160
Operating expenses
Production	310,233			348,387			519,546
Production taxes	15,440			31,731			32,292
Depreciation and depletion—oil and natural gas	319,913			434,295			567,732
Accretion of asset retirement obligations	4,477			9,092			36,777
Impairment	4,473,787			164,779			—
(Gain) loss on derivative contracts	(73,061		)	(334,011		)	47,123
Loss on settlement of contract	50,976			—			—
(Gain) loss on sale of assets	(25		)	(39		)	398,543
Other operating expenses	67,601			54,950			169,638
Total operating expenses	5,169,341			709,184			1,771,651
(Loss) income from operations	$	(4,461,907	)	$	713,716		$	62,509
Production data
Oil (MBbls)	9,600			10,876			14,279
NGL (MBbls)	5,044			3,794			2,291
Natural gas (MMcf)	92,105			85,697			103,233
Total volumes (MBoe)	29,995			28,953			33,776
Average daily total volumes (MBoe/d)	82.2			79.3			92.5
Average prices—as reported(1)
Oil (per Bbl)	$	45.83		$	89.86		$	97.58
NGL (per Bbl)	$	14.36		$	33.41		$	35.16
Natural gas (per Mcf)	$	2.12		$	3.70		$	3.36
Total (per Boe)	$	23.59		$	49.08		$	53.89
Average prices—including impact of derivative contract settlements(2)
Oil (per Bbl)	$	76.80		$	94.18		$	98.90
NGL (per Bbl)	$	14.36		$	33.41		$	35.16
Natural gas (per Mcf)	$	2.45		$	3.58		$	3.46
Total (per Boe)	$	34.51		$	50.36		$	54.79

____________________

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

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

For a discussion of reserves, PV-10 and reconciliation to Standardized Measure, see “Business—Business Segments and Primary Operations—Proved Reserves” in Item 1 of this report.

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The table below presents production by area of operation for the years ended December 31, 2015, 2014 and 2013 and illustrates the impact of (i) the Company’s continued development of its Mid-Continent assets, (ii) the Company’s sale in February 2014 of the Gulf Properties, and (iii) the sale of the Permian Properties in February 2013.

	Year Ended December 31,
	2015			2014			2013
	Production (MBoe)	% of Total Production		Production (MBoe)	% of Total Production		Production (MBoe)	% of Total Production
Mid-Continent	26,558	88.5	%	23,423	80.9	%	17,783	52.7	%
Gulf of Mexico / Gulf Coast	—	—	%	1,321	4.6	%	10,082	29.8	%
Permian Basin	1,567	5.2	%	2,076	7.2	%	3,366	10.0	%
Other - west Texas	1,870	6.3	%	2,133	7.3	%	2,545	7.5	%
Total	29,995	100.0	%	28,953	100.0	%	33,776	100.0	%

Revenues

Exploration and production segment revenues from oil, natural gas and NGL sales decreased by a combined $713.4 million, or 50.2% for the year ended December 31, 2015 compared to 2014. Approximately $664.3 million of the total net decrease was due to a decline in the average prices received primarily for oil production, and to a lesser extent, natural gas and NGL production. The remaining decrease of $49.1 million is due largely to a decrease in oil production, which was partially offset by increases in natural gas and NGL production. The decline in oil production resulted primarily from natural declines in existing producing wells and the decrease in wells drilled during 2015 compared to 2014.

Exploration and production segment revenues from oil, natural gas and NGL sales decreased by a combined $399.4 million, or 21.9% for the year ended December 31, 2014 compared to 2013. Approximately $337.9 million of the total net decrease resulted from a 4.8 MMBoe, or 14.3% decrease in combined production, stemming largely from the sale of the Gulf Properties in February 2014. As illustrated in the table above, the decrease in production resulting from the sale of the Gulf Properties was partially offset by increased production in the Mid-Continent as the Company focused its development efforts in this area. The remainder of the decrease in exploration and production segment revenues was primarily due to a decline in the average price received for oil production.    

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 for 2015 decreased $38.2 million, or 11.0% from 2014. Production costs per Boe decreased to $10.34 per Boe for the 2015 period from $12.03 per Boe in 2014, primarily as a result of (i) the sale of the Gulf Properties in February 2014, which had higher production costs inherent with offshore operations, and (ii) a decrease in well activity as a result of fewer new wells being brought on production and a reduction in workover activity in 2015 in conjunction with an increase in combined production for the year ended December 31, 2015 compared to 2014. Production expenses decreased $171.2 million, or 32.9%, in 2014 compared to 2013, primarily due to the decrease in total production as described above and a decrease in production costs per Boe. For the year ended December 31, 2014, production expense was $12.03 per Boe, down from the rate for 2013 of $15.38 per Boe, primarily as a result of the sale of the Gulf Properties in February 2014.

Production taxes decreased by $16.3 million, or 51.3%, for 2015, compared to 2014, primarily due to the decrease in oil, natural gas and NGL revenues. Production taxes as a percentage of oil, natural gas and NGL revenue were consistent at approximately 2.2% for both 2015 and 2014. Production taxes as a percentage of oil, natural gas and NGL revenue increased to approximately 2.2% for 2014 from 1.8% for 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 $114.4 million for the year ended December 31, 2015, compared to 2014. This decrease largely resulted from a reduction in the average depreciation and depletion rate per Boe to $10.67 for 2015 from $15.00 for 2014, primarily due to (i) the sale of the Gulf Properties in February 2014 (ii) full cost ceiling impairments recorded in 2015 and (iii) changes in future production and planned capital expenditures that occurred in conjunction with the year end 2014 budgeting and reserves estimation processes. Depreciation and depletion for the Company’s oil and natural gas properties decreased by $133.4 million for 2014, compared to 2013, largely as a result of the decrease in the Company’s combined production volumes for the 2014 period as well as a decrease in the average depreciation and depletion rate per Boe to $15.00 for 2014 from $16.81 in 2013. The decrease in the depreciation and depletion rate is primarily

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due to (i) the sale of the Gulf Properties in February 2014 (ii) full cost ceiling impairment recorded in the first quarter of 2014, and (iii) changes in future production and planned capital expenditures.

Accretion of asset retirement obligations decreased $4.6 million for the year ended December 31, 2015, compared to2014, and decreased $27.7 million for the year ended December 31, 2014, compared to 2013, primarily due to Fieldwood’s assumption of asset retirement obligations associated with the Gulf Properties sold in February 2014.

Impairment of $4.5 billion for the year ended December 31, 2015 was due to full cost ceiling limitations recognized in each quarter of 2015, which resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued throughout 2015. Impairment of $164.8 million for the year ended December 31, 2014 was due to a full cost ceiling limitation resulting from the divestiture of the Gulf Properties in the first quarter of 2014 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 year ended December 31, 2013.

While it is difficult to project future impairment write-downs in light of numerous variables involved, the following analysis illustrates the impact of lower commodities pricing on impairment charges. Applying the reduced twelve-month average prices described above under “Outlook” to the December 31, 2015 ceiling test for impairment, the Company estimates the impairment charge for the quarter would have increased by approximately $229.0 million. Accordingly, at this time, the Company expects to incur a further ceiling test impairment write-down in the first quarter of 2016.

The Company recorded a (gain) loss on commodity derivative contracts of $(73.1) million, $(334.0) million and $47.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, as reflected in income from operations for the exploration and production segment, which include net cash (receipts) payments upon settlement of $(327.7) million, $32.3 million and $(0.8) million, respectively. Included in the net cash payments (receipts) for the years ended December 31, 2014 and 2013 are $69.6 million and $29.6 million, respectively, of cash payments related to settlements of commodity derivative contracts with contractual maturities after the year in which they were settled (“early settlements”) 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.

Loss on settlement of contract resulted from the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. See “Overview-Recent Events” above and see “Note 3—Acquisitions and Divestitures” and “Note 4—Variable Interest Entities” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the acquisition of PGC and the PGC gathering agreement.

The Company recorded a loss on the sale of assets of $398.9 million for the year ended December 31, 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—Acquisitions and Divestitures” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of these transactions.

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

Drilling and Oilfield Services Segment

The Company historically has drilled for its own account in northwestern Oklahoma, Kansas and west Texas and for other oil and gas companies, primarily in west Texas, through its drilling and oilfield services subsidiary. Additionally, the Company’s oilfield services business provided pulling units, trucking, rental tools, location and road construction and roustabout services. The financial results of the Company’s drilling and oilfield services segment depended primarily on demand and prices that could be charged for its services. On a consolidated basis, drilling and oilfield service revenues earned and expenses incurred in performing services for third parties, including third-party working interests in wells the Company operates, were included in drilling and services revenues and cost of sales. Drilling and oilfield service revenues earned and expenses incurred in performing

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services for the Company’s own account were eliminated in consolidation. The primary factors affecting the results of the Company’s drilling and oilfield services segment were the rates received on rigs drilling for third parties, the number of days drilling for third parties and the amount of oilfield services provided to third parties.

Demand for the Company’s drilling and oilfield services declined significantly during the latter half of 2014 and throughout 2015 due to downward trends in oil and natural gas prices experienced in those periods. In the first quarter of 2015, as a result of decreased demand for drilling services in the Permian region and the Company’s fulfillment of its drilling obligation with the Permian Trust in November 2014, the Company decided to discontinue all remaining drilling and oilfield services operations in the Permian region. No wells were drilled for third parties after the first quarter of 2015. The Company discontinued substantially all remaining drilling and oilfield services operations in January 2016.

Set forth in the table below is financial and operational information for the drilling and oilfield services segment for the years ended December 31, 2015, 2014 and 2013.

	Year Ended December 31,
	2015			2014			2013
Results (in thousands)
Revenues	$	67,358		$	192,944		$	187,456
Inter-segment revenue	(45,234		)	(116,856		)	(120,815		)
Total revenues	22,124			76,088			66,641
Operating expenses	44,478			86,225			95,692
Impairment	37,645			27,427			11,104
Loss from operations	$	(59,999	)	$	(37,564	)	$	(40,155	)
Drilling rig statistics
Average number of operational rigs owned during the period	11.0			27.0			29.0
Average number of rigs working for third parties	—			4.8			4.4
Number of days drilling for third parties	—			1,749			1,603
Average drilling revenue per day per rig drilling for third parties(1)	$	—		$	14,985		$	14,610
Rig status as of December 31
Working for SandRidge(2)	2			10			11
Working for third parties	—			—			6
Idle(3)	—			15			10
Total operational	2			25			27
Non-operational(4)	—			2			3
Total rigs	2			27			30

____________________

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

(2) Rigs drilling for SandRidge at December 31, 2015, were released in January 2016 and are included in assets held for sale in other current assets on the accompanying consolidated balance sheet at December 31, 2015.

(3) 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.

(4) Non-operational rigs at December 31, 2014 were stacked. Non-operational rigs at December 31, 2013 were held for sale.

Drilling and oilfield services segment revenues and expenses decreased $54.0 million and $41.7 million, respectively, for the year ended December 31, 2015 compared to 2014, primarily due to a decrease in revenue from third party working interests for work performed on wells in which the Company also has an interest, as well as a decrease in the average number of rigs working for third parties.

Drilling and oilfield services segment revenues increased $9.4 million for the year ended December 31, 2014 compared to 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 the average number of rigs working for third parties. Drilling and oilfield

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services segment operating expenses decreased $9.5 million during the year ended December 31, 2014 compared to 2013 due primarily to an increased focus on capital discipline by management as well as the closure of the drilling fluids services business in the Permian region during the fourth quarter of 2014 upon fulfillment of the Permian Trust drilling obligation.

During 2015 and 2014, the Company recorded impairments of approximately $37.6 million and $27.4 million, respectively, on certain drilling assets in order to adjust their carrying values to fair value after classifying certain assets as held for sale or determining that the future use of assets held and used was limited.

Midstream Services Segment

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

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

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

Gas Treating Plants. At December 31, 2015, the Company owned two gas treating plants in west Texas, one of which was transferred to Occidental in January 2016 in the transaction discussed under “Overview- Recent Events” along with substantially all of the Company’s assets located in the Piñon field. The treating plant retained by the Company has been fully impaired due to lack of planned use.

Set forth in the table below is financial information for the midstream services segment for the years ended December 31, 2015, 2014 and 2013.

	Year Ended December 31,
	2015			2014			2013
Results (in thousands)
Operating revenues	$	81,083		$	142,987		$	156,640
Construction contract	—			—			23,349
Inter-segment revenue	(47,274		)	(87,593		)	(100,529		)
Total revenues	33,809			55,394			79,460
Operating expenses	41,879			63,927			73,744
Construction contract	—			—			23,349
Impairment	7,148			561			3,934
Loss from operations	$	(15,218	)	$	(9,094	)	$	(21,567	)
Gas Marketed
Volumes (MMcf)	6,631			7,343			8,006
Price per Mcf	$	2.43		$	4.18		$	3.56

Midstream services segment operating revenues and expenses decreased $21.6 million and $22.0 million, respectively, for the year ended December 31, 2015 compared to the same period in 2014. These decreases were primarily due to (i) a change in the fee structure for electrical usage during the second quarter of 2014, (ii) a decrease in the average price received for natural

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gas purchased and marketed in west Texas of $1.75 per Mcf as well as a decrease in volumes purchased and marketed of 712 MMcf in 2015 compared to 2014, and (iii) a decrease in gas compressor rentals in 2015 compared to 2014.

Midstream services segment operating revenues and expenses, excluding construction contract revenue and expenses decreased $0.7 million and $9.8 million, respectively, for the year ended December 31, 2014 compared to the same period in 2013. These decreases were primarily due to a change in the fee structure for electrical usage during the second quarter of 2014. The decrease in revenues during 2014 compared to 2013 due to the fee structure change was partially offset by (i) an increase in electrical transmission services provided to third-party working interest owners in the Mid-Continent, (ii) an increase of $0.62 per Mcf in the average price received for natural gas purchased and marketed in west Texas, and (iii) an increase in gas compressor and generator rentals.

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 11— Construction Contract” to the Company’s consolidated financial statements in Item 8 of this report.

Midstream services segment expenses for the years ended December 31, 2015, 2014 and 2013 include impairments of $7.1 million, $0.6 million and $3.9 million, respectively, primarily on generators, various other equipment, and its natural gas treating plants in west Texas due to their limited use. All natural gas produced in the WTO during 2015, 2014 and 2013 was processed at the Century Plant subject to the terms of the Company’s 30-year treating agreement with Occidental, which contained minimum CO₂ delivery requirements.

Consolidated Results of Operations

Revenues

The Company’s consolidated revenues for the years ended December 31, 2015, 2014 and 2013 are presented in the table below.

	Year Ended December 31,
	2015		2014		2013
	(In thousands)
Revenues
Oil, natural gas and NGL	$	707,434	$	1,420,879	$	1,820,278
Drilling and services	22,124		76,088		66,586
Midstream and marketing	33,809		55,658		58,304
Construction contract	—		—		23,349
Other	5,342		6,133		14,871
Total revenues(1)	$	768,709	$	1,558,758	$	1,983,388

___________________

(1) Includes $57.0 million, $150.4 million and $199.3 million of revenues attributable to noncontrolling interests in consolidated variable interest entities (“VIEs”), after considering the effects of intercompany eliminations, for the years ended December 31, 2015, 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 Oilfield Services Segment” and discussion of significant midstream and marketing and construction contract revenues under “Results by Segment—Midstream Services Segment.”

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Expenses

The Company’s consolidated expenses for the years ended December 31, 2015, 2014 and 2013 are presented below.

	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Expenses
Production	$	308,701		$	346,088		$	516,427
Production taxes	15,440			31,731			32,292
Cost of sales	24,394			56,155			57,118
Midstream and marketing	26,819			49,905			53,644
Construction contract	—			—			23,349
Depreciation and depletion—oil and natural gas	319,913			434,295			567,732
Depreciation and amortization—other	47,382			59,636			62,136
Accretion of asset retirement obligations	4,477			9,092			36,777
Impairment	4,534,689			192,768			26,280
General and administrative	137,715			113,991			207,920
Employee termination benefits	12,451			8,874			122,505
(Gain) loss on derivative contracts	(73,061		)	(334,011		)	47,123
Loss on settlement of contract	50,976			—			—
Loss on sale of assets	1,491			10			399,086
Total expenses(1)	$	5,411,387		$	968,534		$	2,152,389

___________________

(1) Includes $679.9 million, $51.0 million and $157.0 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2015, 2014 and 2013, respectively. The expenses attributable to noncontrolling interest in consolidated VIEs include $655.9 million and $29.9 million of allocated full cost ceiling impairment for the years ended December 31, 2015 and 2014, respectively, and $71.7 million of allocated loss on sale of assets associated with the sale of the Permian Properties for the year ended December 31, 2013.

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, loss on settlement of contract and 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 Oilfield Services Segment” and discussion of midstream and marketing and construction contract expense and impairment under “Results by Segment—Midstream Services Segment.”

Other impairment expense not discussed within “Results by Segment” for the year ended December 31, 2015, includes a $15.4 million impairment on property located in downtown Oklahoma City, Oklahoma to adjust the carrying value of the property to the price for which the Company sold the property in 2015 as well as $0.7 million in impairment to adjust the carrying value of certain gathering and compression equipment to fair value after determining its future use was limited. Other impairment expense not discussed within “Results by Segment” for the year ended December 31, 2013, primarily consists of $2.9 million in impairment of a corporate asset based on plans to sell this asset in 2013, and an $8.3 million impairment on certain pipe inventory, natural gas compressors, and a CO₂ compressor station after determining that their future use was limited. See “Note 8—Impairment” to the Company’s consolidated financial statements in Item 8 of this report for additional information regarding the Company’s impairments.

General and administrative expenses increased $23.7 million, or 20.8%, for the year ended December 31, 2015 compared to 2014 due primarily to (i) an increase of $14.6 million in professional services costs, including legal and consulting fees, (ii) an increase of $5.0 million due to a legal settlement recorded in 2015, and (iii) a $4.0 million increase in net payroll costs, primarily resulting from a decrease in capitalized salary costs.

General and administrative expenses decreased $93.9 million, or 45.2%, for the year ended December 31, 2014 compared to 2013 due primarily to decreases of (i) $44.5 million in compensation, (ii) $22.2 million in costs related to a stockholder consent solicitation that occurred in 2013, (iii) $9.8 million in professional services costs, (iv) $3.8 million in promotional and advertising

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costs, and (v) $5.5 million in other corporate support costs. The decreases in compensation, professional services costs, promotional and advertising and corporate support costs primarily resulted from corporate cost cutting measures and a decrease in headcount during 2014.

Employee termination benefits of $12.5 million for the year ended December 31, 2015 represent severance costs incurred primarily as a result of (i) a reduction in force (ii) severance costs associated with the departure of an executive officer and other senior officers and (iii) discontinuing all remaining drilling and oilfield services operations in the Permian region in 2015. Employee termination benefits of $8.9 million for the year ended December 31, 2014 represent severance costs incurred primarily in conjunction with the sale of the Gulf Properties. Employee termination benefits of $122.5 million for the year ended December 31, 2013 represent severance costs associated with former Company executives. Of the total employee termination benefits in 2013, approximately $99.3 million, including amounts associated with the accelerated vesting of restricted stock awards, were attributable to the Company’s former Chairman and CEO.

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

The Company’s other income (expense), taxes and net (loss) income attributable to noncontrolling interest for the years ended December 31, 2015, 2014 and 2013 are reflected in the table below.

	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Other income (expense)
Interest expense	$	(321,421	)	$	(244,109	)	$	(270,234	)
Gain (loss) on extinguishment of debt	641,131			—			(82,005		)
Other income, net	2,040			3,490			12,445
Total other income (expense)	321,750			(240,619		)	(339,794		)
(Loss) income before income taxes	(4,320,928		)	349,605			(508,795		)
Income tax expense (benefit)	123			(2,293		)	5,684
Net (loss) income	(4,321,051		)	351,898			(514,479		)
Less: net (loss) income attributable to noncontrolling interest	(623,506		)	98,613			39,410
Net (loss) income attributable to SandRidge Energy, Inc.	$	(3,697,545	)	$	253,285		$	(553,889	)

Interest expense for the years ended December 31, 2015, 2014 and 2013 consisted of the following:

	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Interest expense
Interest expense on debt	$	304,020		$	254,475		$	277,746
Amortization of debt issuance costs, discounts and premium	15,014			9,954			11,127
Write off of debt issuance costs	7,108			—			—
Loss on long-term debt derivatives	10,377			—			—
Loss on interest rate swaps	—			—			14
Capitalized interest	(14,018		)	(19,718		)	(16,691		)
Total	322,501			244,711			272,196
Less: interest income	(1,080		)	(602		)	(1,962		)
Total interest expense	$	321,421		$	244,109		$	270,234

Total interest expense increased $77.3 million for the year ended December 31, 2015 compared to 2014, primarily due to interest expense associated with the $1.25 billion in Senior Secured Notes issued in June 2015. This increase was partially offset by a decrease in interest paid on Senior Unsecured Notes that were repurchased or converted into shares of the Company’s common stock in 2015 as well as the loss recognized due to an increase in the fair value of derivatives embedded in certain of the Company’s long-term debt during the year ended December 31, 2015. Total interest expense decreased $26.1 million for the year ended

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December 31, 2014 compared to 2013, primarily due to a reduction in interest expense associated with the senior notes repurchased and redeemed in the first quarter of 2013.

The Company recognized a gain on extinguishment of debt of $641.1 million for the year ended December 31, 2015, primarily in connection with (i) the exchange of $575.0 million in aggregate principal of the Company’s Senior Unsecured Notes for Convertible Senior Unsecured Notes in 2015, (ii) the repurchase of $350.0 million in aggregate principal of the Company’s Senior Unsecured Notes for approximately $124.5 million in cash, (iii) the exchange of approximately $50.0 million aggregate principal of the Company’s 7.5% senior unsecured notes due 2021 and 8.125% senior unsecured notes due 2022 for shares of the Company’s common stock during 2015, and (iv) conversions of the Company’s Convertible Senior Unsecured Notes into shares of the Company’s common stock during 2015.

The Company recognized a loss on extinguishment of debt of $82.0 million for the year ended December 31, 2013 in connection with the redemption of the Company’s 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018. The loss on extinguishment represents the premium paid to purchase the notes and the expense incurred to write off of the remaining unamortized debt issuance costs associated with the notes.

See “Note 12—Long-Term Debt” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the Company’s long-term debt transactions.

The Company’s tax expense and effective tax rate for the year ended December 31, 2015 continue to be low as a result of the valuation allowance against its net deferred tax asset. The Company’s income tax benefit of $2.3 million for the year ended December 31, 2014 is primarily related to a reduction in the Company’s gross unrecognized tax benefits following a favorable outcome pertaining to the Company’s state income tax audits in the amount of $1.3 million as well as a reduction in federal alternative minimum tax (“AMT”) associated with the tax year ended December 31, 2014 in the amount of $1.2 million. With respect to the AMT, the Company reduced each of the current tax liability and corresponding deferred tax asset upon finalizing and filing the Company’s federal income tax return for the year ended December 31, 2014. As a result of reducing the deferred tax asset, the Company decreased its valuation allowance against its net deferred tax asset by $1.2 million. The Company reported income tax expense of $5.7 million for the year ended December 31, 2013, primarily related to AMT associated with the tax year ended December 31, 2013. The Company recorded a current tax liability and a corresponding deferred tax asset each in the amount of approximately $3.8 million at December 31, 2013. As a result of recording this deferred tax asset, the Company increased its valuation allowance against its net deferred tax asset by approximately $3.8 million. Also included in the income tax expense for the year ended December 31, 2013, is $2.4 million of current state income tax, which is partially offset by a reduction to the liability associated with unrecognized tax benefits.

Net (loss) income attributable to noncontrolling interest represents the portion of (loss) income attributable to third-party ownership in the Company’s consolidated VIEs and subsidiaries. The net loss attributable to noncontrolling interest for the year ended December 31, 2015 includes full cost ceiling impairments attributable to noncontrolling interest of $655.9 million compared to a full cost ceiling impairment attributable to noncontrolling interest of $29.9 million in 2014. Revenues for the Royalty Trusts also decreased in the 2015 periods compared to the 2014 periods largely as a result of a decrease in average prices received for production, natural declines in production and a reduction in the average number of producing wells attributable to the Royalty Trusts’ royalty interest, as uneconomic wells were shut-in due to continued depressed commodity pricing. Additionally, net gains recorded on the Royalty Trusts’ derivative contracts decreased in 2015 compared to 2014, primarily due to the expiration of the Permian Trust’s derivative contracts in the first quarter of 2015. The Company fulfilled its drilling obligations to the Mississippian Trust I in the second quarter of 2013, to the Permian Trust in the fourth quarter of 2014 and to the Mississippian Trust II in the first quarter of 2015. No further wells will be drilled for the Royalty Trusts.

Net income attributable to noncontrolling interest increased to $98.6 million for the year ended December 31, 2014 compared to $39.4 million in 2013 due primarily to (i) net gains recognized on the Royalty Trusts’ derivative contracts during 2014 compared to net losses recognized during 2013 and (ii) the recognition of a full cost ceiling impairment attributable to noncontrolling interest of $29.9 million in 2014 compared to the recognition of a loss on the sale of the Permian Properties attributable to noncontrolling interest of $71.7 million in 2013. These increases were 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

As of December 31, 2015, the Company’s cash and cash equivalents were $435.6 million, including $7.8 million attributable to the Company’s consolidated VIEs which is available to satisfy only obligations of the VIEs. The Company had approximately $3.6 billion in total debt outstanding and $11.0 million in outstanding letters of credit with no amount outstanding under its senior credit facility at December 31, 2015. As of and for the year ended December 31, 2015, the Company was in

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compliance with applicable covenants under its senior credit facility and outstanding senior notes. As of March 23, 2016, the Company’s cash and cash equivalents were approximately $691.7 million, including $7.8 million attributable to the Company’s consolidated VIEs.

At December 31, 2015 the senior credit facility had a borrowing base of $500.0 million that was undrawn. During January 2016, the Company borrowed the available capacity under the senior credit facility, or $488.9 million, and such amounts remained outstanding at March 23, 2016. As of March 23, 2016, the proceeds of the borrowed funds under the senior credit facility were held by the Company in a securities account. On each such date, the Company had, $11.0 million and $10.4 million, respectively, in outstanding letters of credit secured by the senior credit facility, which reduce availability under the senior credit facility on a dollar for dollar basis. On March 11, 2016, the administrative agent of the senior credit facility notified the Company that the lenders had elected to reduce the borrowing base to $340.0 million pursuant to a special redetermination. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties. Continued low oil and natural gas prices or further declines in such prices could result in further proposed reduction in the size of the borrowing base under the senior credit facility, or an inability to borrow thereunder, which would further limit capital expenditures.

The Company’s primary sources of liquidity and capital resources are proceeds from the issuance of debt securities, cash flows from operating activities, borrowings under the senior credit facility, proceeds from monetizations of assets and the issuance of equity securities. The Company’s primary uses of capital are expenditures related to its oil and natural gas properties, such as costs related to the drilling and completion of wells, the acquisition of oil and natural gas properties and other fixed assets, interest payments on its outstanding debt, the repayment or repurchase of long-term debt, and the payment of dividends on its outstanding convertible perpetual preferred stock if, and when, the Company elects to pay such dividends in cash. Historically, the Company has availed itself of regular access to the capital and credit markets as part of its growth plan. However, as a result of sustained depressed commodity prices, the capital markets that the Company has historically accessed are currently constrained to such an extent that debt or equity capital raises are practically unfeasible. If the debt and equity capital markets do not improve, the Company may be unable to implement its drilling and development plans or otherwise carry out its business strategy as expected.

The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, each of 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, from January 2011 through December 2015, the highest month end NYMEX settled price for oil was $113.93 per Bbl and the lowest was $37.04 per Bbl. Oil prices dropped sharply during the latter half of 2014 and have continued to decline throughout 2015 and into 2016, and settled as low as $26.21 per Bbl in February 2016. For natural gas, from January 2011 through December 2015, the highest month end NYMEX settled price was $5.56 per MMBtu and the lowest was $2.03 per MMBtu. Declines in market price for production directly reduce the Company’s cash flow from operations and indirectly impacts its other potential sources of funds described above. While the Company’s derivative arrangements serve to mitigate a portion of the effect of this price volatility on its cash flows, this extended period of depressed commodity prices has limited the Company’s ability to add meaningful volumes to its hedge positions. If the current depressed oil or natural gas prices persist for a prolonged period or further decline, they would have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced, likely resulting in further full cost pool ceiling impairments.

The Company’s 2016 budget for capital expenditures is approximately $285.0 million, representing a 59% reduction from the Company’s actual capital expenditures in 2015. The Company expects to fund its near term capital and debt service requirements and working capital needs with cash on hand ($435.6 million at December 31, 2015), cash flows from operations and net amounts drawn under its senior credit facility during 2016.

In light of impacts to the Company’s financial position resulting from declining industry conditions and the Company’s leverage position, the Company has engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. The Company is also focused on cost reductions, including the identification of non-core assets for potential sale. There can be no assurance that any restructuring transaction will occur as a result of such discussions with stakeholders, that the terms of any potential restructuring transaction or other transactions would be acceptable to the Company or that such transactions would be successful. As a result of these uncertainties and the likelihood

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of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern as it is currently structured.

On February 16, 2016, the Company elected to defer interest payments then due with respect to its 7.5% Senior Notes due 2023 and its Senior Convertible Notes due 2023 (collectively, the “2023 Notes”). On March 15, 2016, the Company made a payment of approximately $22 million in satisfaction of its obligations under the 2023 Notes. Further, on March 16, 2016, the Company made approximately $28.4 million in interest payments then due with respect to its 7.5% Senior Notes due 2021.

In consideration of the events described above, the report of the independent registered public accounting firm that accompanies the audited consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding substantial doubt as to the Company’s ability to continue as a going concern. Inclusion of such an explanatory paragraph constitutes a covenant violation under the senior credit facility agreement. The senior credit facility agreement provides for a 30-day grace period for a breach of this covenant. If the Company does not obtain a waiver of this covenant or otherwise cure this event within 30 calendar days of the issuance of the consolidated financial statements, the lenders under the senior credit facility will be able to accelerate the maturity of the debt. Any acceleration of the obligations under the senior credit facility would result in a cross-default and potential acceleration of the Company’s other outstanding long-term debt. Currently, the Company has no contractual maturities of long-term debt prior to 2020, provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019.

Working Capital

At December 31, 2015, the Company had a working capital surplus of $236.7 million compared to a surplus of $47.5 million at December 31, 2014. Current assets decreased by $157.8 million and current liabilities decreased by $347.1 million at December 31, 2015 compared to December 31, 2014. The increase in current assets is primarily due to a $254.3 million increase in cash and cash equivalents, resulting largely from the receipt of $1.21 billion in net proceeds from the issuance of the Senior Secured Notes in June 2015, which were partially used to fund capital expenditures, the acquisition of the Rockies assets, the acquisition of and termination of a gas gathering agreement with PGC and debt repurchases. The increase in cash was partially offset by a decrease of $207.1 million in the net asset position of the Company’s current derivative contracts and a decrease of $202.7 million in accounts receivable, largely resulting from fluctuations in the timing and amount of collections of receivables. The change in current liabilities is primarily due to a decrease of $255.0 million in accounts payable and accrued expenses largely due to (i) a reduction in accrued capital expenditures resulting from a decrease in the number of drilling rigs operating on the Company’s properties, (ii) a decrease in revenue payable to third party owners in wells operated by the Company due largely to declining average prices received for oil, gas and NGLs, and (iii) other changes due primarily to fluctuations in the timing and amount of the payment of expenditures related to exploration and production operations during the year ended December 31, 2015.

Cash Flows

The Company’s cash flows for the years ended December 31, 2015, 2014 and 2013 are presented in the following table and discussed below:

	Year Ended December 31,
	2015			2014			2013
	(In thousands)
Cash flows provided by operating activities	$	373,537		$	621,114		$	868,630
Cash flows (used in) provided by investing activities	(1,039,640		)	(857,241		)	1,070,356
Cash flows provided by (used in) financing activities	920,438			(397,283		)	(1,434,089		)
Net increase (decrease) in cash and cash equivalents	$	254,335		$	(633,410	)	$	504,897

Cash Flows from Operating Activities

The Company’s operating cash flow is primarily influenced by the prices the Company receives for its oil, natural gas and NGLs, the quantity of oil, natural gas and NGLs it sells, settlements of derivative contracts, and third-party demand for its drilling rigs and oilfield 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 year ended December 31, 2015 decreased by $247.6 million, or 39.9% compared to 2014 primarily due to a reduction in revenues from oil, natural gas and NGLs, largely resulting from a decrease in

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average prices received for the Company’s production. The decrease in revenues was partially offset by gains received on the settlement of commodity derivative contracts and, to a lesser extent, a reduction in operating expenses during the year ended December 31, 2015.

Net cash provided by operating activities for the year ended December 31, 2014 decreased by $247.5 million, or 28.5% compared to 2013 primarily due to a decrease in revenues from oil, natural gas and NGL production resulting from the sale of the Gulf Properties in February 2014, as well as changes in operating assets and liabilities during 2014, primarily related to the timing of cash receipts and disbursements.

Cash Flows from Investing Activities

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

During the year ended December 31, 2015, cash flows used in investing activities largely consisted of capital expenditures, excluding acquisitions, as well as cash paid for the North Park acquisition and the PGC assets acquired. During the year ended December 31, 2014, cash flows used in investing activities resulted from capital expenditures, excluding acquisitions, of approximately $1.6 billion, which were partially offset by proceeds from the sale of assets of $714.5 million, primarily generated by the sale of the Gulf Properties. During 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 years ended December 31, 2015, 2014 and 2013 are summarized below:

	Year Ended December 31,
	2015		2014		2013
	(In thousands)
Capital expenditures
Exploration and production	$	656,022	$	1,508,100	$	1,319,012
Drilling and oilfield services	4,632		18,385		7,125
Midstream services	21,556		44,606		55,706
Other	19,405		37,798		42,040
Capital expenditures, excluding acquisitions	701,615		1,608,889		1,423,883
Acquisitions	241,165		18,384		17,028
Total	$	942,780	$	1,627,273	$	1,440,911

Capital expenditures, excluding acquisitions, decreased by $907.3 million for the year ended December 31, 2015 compared to 2014, primarily due to a decrease in drilling and leasehold expenditures. The number of drilling rigs operating on the Company’s properties decreased to four rigs at December 31, 2015 from 35 rigs at December 31, 2014. Capital expenditures, excluding acquisitions, increased by $185.0 million for the year ended December 31, 2014 compared to 2013, primarily due to an increase in drilling and leasehold expenditures in the Mid-Continent area.

During the years ended December 31, 2014 and 2013, the Company received payments for drilling carries from Atinum MidCon I, LLC’s (“Atinum”) and Repsol E&P USA, Inc. of approximately $205.6 million and $408.0 million, respectively, which directly offset the Company’s capital expenditures for the respective periods. As of December 31, 2014, both Atinum and Repsol had fully funded their drilling carry commitments.

During the fourth quarter of 2015, the Company acquired (i) all of the assets of PGC for approximately $47.3 million and (ii) approximately 135,000 net acres and 16 existing oil and natural gas wells in the North Park Basin of the Rockies, in Jackson County, Colorado for approximately $191.1 million in cash, including post-closing adjustments. The seller of the North Park Basin properties also paid the Company $3.1 million for certain overriding interests retained in the properties, which slightly offset acquisition expenditures.

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Cash Flows from Financing Activities

The Company’s financing activities provided $920.4 million in cash for the year ended December 31, 2015 compared to using $397.3 million of cash in 2014. The change of $1.3 billion is due primarily to (i) the issuance of $1.25 billion in Senior Secured Notes in June 2015, which was partially offset by $124.5 million in cash paid for the repurchase of debt, and debt issuance costs incurred of $53.2 million, (ii) a decrease of $55.5 million in noncontrolling interest distributions, and (iii) a decrease of $44.3 million in preferred dividends paid in cash during the 2015 period compared to the 2014 period. The decrease in cash dividends paid was primarily due to payment of the semi-annual 7.0% preferred share dividend in May 2015 and the semi-annual 8.5% preferred share dividend in August 2015 in shares of the Company’s common stock, suspension of the 7.0% preferred share dividend prior to the November semi-annual payment, and conversion of the 6.0% preferred shares to common shares in December 2014. Additionally, during the year ended December 31, 2014, the Company paid $111.3 million, net of $0.5 million in broker fees and commissions, to repurchase shares of the Company’s common stock, as noted below, and $44.1 million for the early settlement of financing derivatives as a result of the sale of the Gulf Properties. These payments were partially offset by proceeds from the sale of Royalty Trust units of $22.1 million.

The Company’s financing activities used $397.3 million in cash for the year ended December 31, 2014 compared to using $1.4 billion of cash in 2013. This 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 year ended December 31, 2013, and a decrease of $24.3 million in treasury stock purchases as a result of a reduction in shares of restricted stock that were traded for taxes upon vesting during 2014 compared to 2013. Partially offsetting these decreases were payments in 2014 of $111.3 million, net of $0.5 million in broker fees and commissions, to repurchase shares of the Company’s common stock, as noted below, and $44.1 million for the early settlement of financing derivatives as a result of the sale of the Gulf Properties.     

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. Payments for shares repurchased under the program have been funded using the Company's working capital. During the year ended December 31, 2014, 27.4 million shares were repurchased under the program for approximately $111.3 million, net of broker fees and commissions, and were immediately retired. The Company did not repurchase any shares of its common stock under the share repurchase program in 2015 and does not currently anticipate repurchasing additional shares under the share repurchase program in 2016. See “Note 16—Equity” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the share repurchase program.

Indebtedness

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

Senior credit facility	$	—
8.75% Senior Secured Notes due 2020, including mandatory prepayment feature liabilities of $2,941, and net of $29,842 discount	1,301,098
Senior Unsecured Notes
8.75% Senior Notes due 2020, net of $3,269 discount	392,666
7.5% Senior Notes due 2021, including a premium of $1,944	759,711
8.125% Senior Notes due 2022	527,737
7.5% Senior Notes due 2023, net of $1,989 discount	541,572
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount	82,294
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount	26,428
Total debt	$	3,631,506

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 year ended December 31, 2015, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding senior notes.

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Senior Credit Facility. At December 31, 2015, the Company had no amount outstanding under the senior credit facility and $11.0 million in outstanding letters of credit, which reduced the availability under the senior credit facility to $488.9 million. As of and during the year ended December 31, 2015, the Company was in compliance with all applicable financial covenants under the senior credit facility.

The amount the Company may borrow under its senior credit facility is limited to a borrowing base, and is subject to periodic redeterminations. The Company’s borrowing base is generally redetermined in April and October of each year. The borrowing base is determined based upon the discounted present value of future cash flows attributable to the Company’s proved reserves. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, a decrease in such value, whether due to declining commodity prices or a reduction in the Company’s development of reserves would likely cause a reduction in the borrowing base. On June 10, 2015, in connection with an amendment to the senior credit agreement, as discussed further below, the borrowing base was reduced to $500.0 million from $900.0 million, which resulted in the write off of approximately $4.9 million of capitalized debt issuance costs. The borrowing base remained unchanged as a result of the October 2015 redetermination.The next scheduled redetermination is expected to take place in April 2016; however, as discussed further below, in March 2016 the borrowing base was reduced to $340.0 million pursuant to a special redetermination.

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

The amended senior credit facility is available to be drawn on subject to limitations based on its terms, including the Company’s ability to make representations and warranties contained therein regarding the value of the Company’s assets versus its liabilities, and compliance with certain financial covenants, including maintenance of agreed upon levels for the (i) ratio of total secured debt under the senior credit facility to EBITDA described above and (ii) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. For the purpose of the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s commodity derivative contracts are disregarded. The senior credit facility matures on the earlier of March 2, 2020 and 91 days prior to the earliest date of any maturity under or mandatory offer to repurchase the Company’s currently outstanding senior notes. Quarterly, the Company pays a commitment fee assessed at an annual rate of 0.5% on any available portion of the senior credit facility.

The amended senior credit agreement permits the Company and certain of its subsidiaries to incur additional indebtedness in an aggregate principal amount not to exceed $1.75 billion, which may be secured solely by collateral securing the senior credit facility on a junior lien basis. Any junior lien debt shall be subject to the terms and conditions set forth in an intercreditor agreement, the terms of which are subject to the approval of the lenders, and shall mature no earlier than January 21, 2020. The borrowing base under the senior credit facility will be reduced by $0.25 for every $1.00 of junior debt incurred in excess of $1.50 billion. At December 31, 2015, the Company had incurred $1.3 billion in junior lien debt as a result of the issuance of the Senior Secured Notes in June 2015 and October 2015 and entered into an intercreditor agreement in connection therewith.

In January 2016, the Company borrowed all of its remaining available capacity under the senior credit facility, or $488.9 million. On March 11, 2016, the administrative agent notified the Company that the lenders had elected to reduce the borrowing base to $340.0 million from $500.0 million pursuant to a special redetermination. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties.

Senior Secured Notes. On June 10, 2015, the Company completed the issuance of $1.25 billion in aggregate principal amount of its Senior Secured Notes, which bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due upon maturity. An additional $78.0 million principal amount of Senior Secured Notes was issued as partial consideration for the Company’s acquisition of and cancellation of a gas gathering agreement with PGC in October 2015. The

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Senior Secured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on a second-priority secured basis by certain of the Company’s wholly owned subsidiaries. Pursuant to the indenture, the Senior Secured Notes will mature on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019.

The Senior Secured Notes are secured by second-priority liens on all of the Company’s and certain of the Company’s wholly owned subsidiaries’ assets that secure the senior credit facility on a first-priority basis; provided, however, the security interest in those assets that secure the Senior Secured Notes and the guarantees will be contractually subordinated to liens thereon that secure the senior credit facility and certain other permitted indebtedness. Consequently, the Senior Secured Notes and the guarantees will be effectively subordinated to the senior credit facility and such other indebtedness to the extent of the value of such assets. The Senior Secured Notes issued in conjunction with the acquisition of and termination of the gas gathering agreement with PGC were issued at a discount that is being amortized into interest expense over the term of the Senior Secured Notes.

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

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

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

For more information about the senior credit facility and senior notes, see “Note 12—Long-Term Debt” to the Company’s consolidated financial statements in Item 8 of this report. For information on the future maturities of the Company’s long-term debt, see the table below under “Contractual Obligations and Off-Balance Sheet Arrangements.”

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Contractual Obligations and Off-Balance Sheet Arrangements

As of December 31, 2015, the Company had future contractual payment commitments under various agreements which are not recorded in the accompanying consolidated balance sheets. A summary of the Company’s contractual obligations as of December 31, 2015 is provided in the following table (in thousands):

	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Long-term debt obligations(1)	$	5,579,384	$	316,805	$	633,610	$	2,257,110	$	2,371,859
Transportation and throughput agreements	64,068		14,082		28,032		10,866		11,088
Third-party drilling rig agreements(2)	2,457		2,457		—		—		—
Asset retirement obligations	103,578		8,399		7,029		3,138		85,012
Operating leases and other(3)	30,180		3,318		5,061		1,333		20,468
Total	$	5,779,667	$	345,061	$	673,732	$	2,272,447	$	2,488,427

____________________

(1) Includes interest on long-term debt and assumes debt principal amounts are outstanding until their latest contractual maturity, with no additional conversions of Convertible Senior Notes to common stock. As such, the outstanding liability balances as of December 31, 2015 for the long-term debt holder conversion feature of $29.4 million and the mandatory prepayment feature for the PGC Senior Secured Notes of $2.9 million are not included in the table above. See “Note 5—Fair Value Measurements” and “Note 13—Derivatives” for discussion of these additional obligations.

(2) Includes drilling contracts with third-party drilling rig operators at specified day or footage rates and termination fees associated with the Company’s hydraulic fracturing services agreements. All of the Company’s drilling rig contracts contain operator performance conditions that allow for pricing adjustments or early termination for operator nonperformance.

(3) Includes the Company’s obligation for the employee and employer match contributions to the participants of its non-qualified deferred compensation plan for eligible highly compensated employees who elect to defer income exceeding the Internal Revenue Service annual limitations on qualified 401(k) retirement plans.

Drilling Carry Commitment. As of December 31, 2015, the Company had drilled 453 net wells under a drilling carry arrangement with Repsol and did not satisfy the total drilling commitment under the arrangement of 484 net wells in the area of mutual interest, within the required time period, which ended May 31, 2015. As a result, the Company will carry a portion of Repsol’s drilling and completion costs up to approximately $31.0 million for wells drilled in the future in the related area of mutual interest. The Company incurred approximately $16.1 million in costs toward this obligation during the year ended December 31, 2015, and will continue to record such costs as they are incurred in future periods. See “Note 7—Property, Plant and Equipment” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion.

Treating Agreement. At December 31, 2015, the Company was party to a 30-year treating agreement with Occidental, under which it was required to deliver a total of approximately 3,200 Bcf of CO₂ by 2041. The Company was obligated to pay Occidental $0.25 per Mcf to the extent minimum annual CO₂ volumes were not met and had accrued approximately $109.9 million in such penalties through December 31, 2015. The Company was released from all past, current and future obligations related to this agreement in January 2016 as discussed under “Overview - Recent Events.”

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 in the period ending December 31, 2008. This valuation allowance has been maintained since 2008. See “Note 19—Income Taxes” to the Company’s consolidated financial statements in Item 8 of this report for more discussion on the establishment of the valuation allowance against the Company’s net deferred tax asset.

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

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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—Acquisitions and Divestitures” to the Company’s consolidated financial statements in Item 8 of this 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 December 31, 2015. One contributing factor to the cumulative negative earnings position for the 36-month period ended December 31, 2015 is the combined effect of the quarterly impairments of the Company’s assets totaling $4.8 billion. 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.

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 December 31, 2015, is difficult to overcome with any forms of positive evidence that may exist. Accordingly, management has not changed its judgment regarding the need for a full valuation allowance against its net deferred tax asset. The valuation allowance against the Company’s net deferred tax asset at December 31, 2015 was $1.9 billion. The Company’s net deferred tax asset position and corresponding valuation allowance significantly increased from December 31, 2014, primarily as a result of the effect of the aforementioned asset impairments recorded during the year ended December 31, 2015. The Company’s net deferred tax asset position and corresponding valuation allowance at December 31, 2014 was $0.6 billion.

Additionally, at December 31, 2015, the Company has valuation allowances totaling $92.0 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.

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company’s financial statements requires the Company to make assumptions and prepare estimates that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. The Company bases its estimates on historical experience and various other assumptions that the Company believes are reasonable; however, actual results may differ significantly. The Company’s critical accounting policies and additional information on significant estimates used by the Company are discussed below. See “Note 1—Summary of Significant Accounting Policies” to the Company’s consolidated financial statements in Item 8 of this report for additional discussion of the Company’s significant accounting policies.

Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates and issue long-term debt that contains embedded derivatives.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. Accordingly, the Company’s earnings may fluctuate significantly as a result of changes in fair value. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities

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unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows.

Fair values of the substantial majority of the Company’s commodity derivative financial instruments are determined primarily by using discounted cash flow calculations or option pricing models, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be corroborated from active markets. Estimates of future prices are based upon published forward commodity price curves for oil and natural gas instruments. Valuations also incorporate adjustments for the nonperformance risk of the Company or its counterparties, as applicable.

In August 2015, the Company issued its Convertible Senior Unsecured Notes, each of which contain a conversion option whereby the Convertible Senior Unsecured Notes holders have the option to convert the notes into shares of Company common stock. These conversion features have been identified as embedded derivatives that meet the criteria to be bifurcated from their host contracts, the Convertible Senior Unsecured Notes, and accounted for separately from those notes. The holder conversion features are recorded at fair value each reporting period, which was determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) recovery rate, (iv) hazard rate and (v) expected volatility. The significant unobservable input used in the fair value measurement of the conversion features is the hazard rate, an estimate of default probability.

In October 2015, the Company issued the PGC Senior Secured Notes. The PGC Senior Secured Notes will mature on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019. The issuance of the PGC Senior Secured Notes at a substantial discount, as discussed in “Note 12—Long-Term Debt” and “Note 13—Derivatives” to the Company’s consolidated financial statements included in Item 8 of this report, resulted in the treatment of the mandatory prepayment feature contained in those notes as an embedded derivative that meets the criteria to be bifurcated from its host contract, the PGC Senior Secured Notes, and is recorded at fair value each reporting period based upon values determined through the use of discounted cash flow models of the PGC Senior Secured Notes both (i) with the mandatory prepayment feature and (ii) excluding the mandatory prepayment feature.

Proved Reserves. Approximately 90.1% of the Company’s reserves were estimated by independent petroleum engineers for the year ended December 31, 2015. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Company’s control. Estimating reserves is a complex process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2015, 2014 and 2013, the Company revised its proved reserves from prior years’ reports by approximately (234.6) MMBoe, 20.3 MMBoe and (19.2) MMBoe, respectively, due to market prices during or at the end of the applicable period, production performance indicating more (or less) reserves in place, larger (or smaller) reservoir size than initially estimated or additional proved reserve bookings within the original field boundaries. Estimates of proved reserves are key components of the Company’s most significant financial estimates used to determine depreciation and depletion on oil and natural gas properties and its full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect the Company’s future depreciation and depletion expenses.

Method of Accounting for Oil and Natural Gas Properties. The Company’s business is subject to accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full cost method. The Company uses the full cost method to account for its oil and natural gas properties. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Exploration and development costs include dry well costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil, natural gas and NGL reserves. Amortization of oil and natural gas properties is calculated using the unit-of-production method based on estimated proved oil, natural gas and NGL reserves. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant

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alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion and impairment of oil and natural gas properties are generally calculated on a well by well, lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all sales of oil and natural gas properties under the successful efforts method. As a result, the Company’s financial statements will differ from companies that apply the successful efforts method since the Company will generally reflect a higher level of capitalized costs as well as a higher oil and natural gas depreciation and depletion rate, and the Company will not have exploration expenses that successful efforts companies frequently have.

Impairment of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved oil, natural gas and NGL reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less related tax effects (the “ceiling limitation”). The Company calculates its full cost ceiling limitation using the 12-month average oil and natural gas prices for the most recent 12 months as of the balance sheet date and adjusted for basis or location differential, held constant over the life of the reserves. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Company recorded full cost ceiling impairments of $4.5 billion and $164.8 million for the years ended December 31, 2015 and 2014. There were no full cost ceiling impairments recorded during the year ended December 31, 2013. See “Results by Segment” for additional discussion of full cost ceiling impairments.

Unproved Properties. The balance of unproved properties consists primarily of costs to acquire unproved acreage. These costs are initially excluded from the Company’s amortization base until it is known whether proved reserves will or will not be assigned to the property. The Company assesses all properties, on an individual basis or as a group if properties are individually insignificant, classified as unproved on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis. The Company estimates that substantially all of its costs classified as unproved as of the balance sheet date will be evaluated and transferred within a 10-year period from the date of acquisition, contingent on the Company’s capital expenditures and drilling program.

Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in operations. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset or asset group may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If an asset or asset group is determined to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. The Company may also determine fair value by using the present value of estimated future cash inflows and/or outflows, or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Changes in such estimates could cause the Company to reduce the carrying value of property and equipment.

See “Note 8—Impairment” to the Company’s consolidated financial statements in Item 8 of this report for a discussion of the Company’s impairments.

Asset Retirement Obligations. Asset retirement obligations represent the estimate of fair value of the cost to plug, abandon and remediate the Company’s wells at the end of their productive lives, in accordance with applicable federal and state laws. The

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Company estimates the fair value of an asset’s retirement obligation in the period in which the liability is incurred (at the time the wells are drilled or acquired). Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. The Company employs a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.

Revenue Recognition and Natural Gas Balancing. Oil, natural gas and NGL revenues are recorded when title of production sold passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves.

The Company accounted for its construction contract, discussed in “Note 11—Construction Contract” to the Company’s consolidated financial statements in Item 8 of this report, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the consolidated balance sheets. Contract losses are recorded at the time it is determined that a loss will be incurred. Contract gains, if any, are recorded upon substantial completion of the construction project.

The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized at the time mobilization services are performed.

In general, natural gas purchased and sold by the midstream business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, since the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold.

Income Taxes. Deferred income taxes are recorded for temporary differences between financial statement and income tax bases. Temporary differences are differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns. As of December 31, 2015, the Company continued to have a full valuation allowance against its net deferred tax asset. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence.

Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE and the significance of the variable interest, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements. In addition to the VIEs that the Company consolidates, during the years ended December 31, 2013 and 2014 and for a portion of 2015, the Company also held 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

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events have occurred that could cause the primary beneficiary to change. See “Note 4—Variable Interest Entities” to the Company’s consolidated financial statements in Item 8 of this report for a discussion of the Company’s VIEs.

New Accounting Pronouncements. For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1—Summary of Significant Accounting Policies” to the Company’s consolidated financial statements in Item 8 of this report.

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Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

General

This discussion provides information about the financial instruments the Company uses to manage commodity prices and interest rate volatility, 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.

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

The Company uses, and may continue to use, a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At December 31, 2015, the Company’s commodity derivative contracts consisted of fixed price swaps, basis swaps and collars, which are described below:

Fixed price swaps	The Company receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Basis swaps	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for oil or natural gas from a specified delivery point.
Collars	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be NYMEX plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

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

At December 31, 2015, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2016 - December 2016	1,464	$	88.36

Natural Gas Basis Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way

	Notional (MBbls)	Sold Put		Purchased Put		Sold Call
January 2016 - December 2016	2,556	$	83.14	$	90.00	$	100.85

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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 future prices as of period-end compared to the contract price.

The Company recorded (gain) loss on commodity derivative contracts of $(73.1) million, $(334.0) million and $47.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(327.7) million, $32.3 million and $(0.8) million, respectively. Included in these net cash payments (receipts) for the years ended December 31, 2014 and 2013, are $69.6 million and $29.6 million of cash payments related to early settlements primarily as a result of the sale of the Gulf Properties in February 2014 and the Permian Properties in February 2013, respectively. For the year ended December 31, 2013, the gain on commodity derivative contracts is net of a non-cash loss of $117.1 million resulting from the amendment of certain 2012 derivative contracts to contracts maturing in 2014 and 2015.

See “Note 13—Derivatives” to the Company’s consolidated financial statements in Item 8 of this 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 December 31, 2015, the counterparties to the Company’s open commodity derivative contracts consisted of eight financial institutions, three of which are also lenders under the Company’s senior credit facility.

The Company’s ability to fund its capital expenditure budget is partially dependent upon the availability of funds under its senior credit facility. In order to mitigate the credit risk associated with individual financial institutions committed to participate in the senior credit facility, the Company’s bank group consists of 11 financial institutions with commitments ranging from 1.00% to 14.00% of the borrowing base as of December 31, 2015.

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 the LIBOR and the federal funds rate. The Company had no outstanding variable rate debt as of December 31, 2015.

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 2012. The Company recorded an insignificant loss on its interest rate swaps for the year ended December 31, 2013. The interest rate swap was not designated as a hedge.

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Item 8.        Financial Statements and Supplementary Data

The Company’s consolidated financial statements required by this item are included in this report beginning on page F-1.

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Item 9.        Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

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Item 9A.    Controls and Procedures

Disclosure Controls and Procedures.

Under the supervision and with the participation of the Company’s management, including its Chief Executive Officer and Chief Financial Officer, the Company performed an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(b) and 15d-15(b) as of the end of the period covered by this annual report. Based on that evaluation, the Company’s Chief Executive Officer and its Chief Financial Officer concluded that its disclosure controls and procedures were effective as of December 31, 2015 to provide reasonable assurance that the information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm

The information required to be filed pursuant to this item is set forth under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” in Item 8 of this report.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Item 9B.    Other Information

Not Applicable.

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PART III

Item 10.        Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 29, 2016: “Director Biographical Information,” “Executive Officers,” “Compliance with Section 16(a) of the Exchange Act” and “Corporate Governance Matters.”

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Item 11.        Executive Compensation

The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 29, 2016: “Director Compensation,” “Outstanding Equity Awards” and “Executive Officers and Compensation.”

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Item 12.        Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 29, 2016: “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management.”

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Item 13.        Certain Relationships and Related Transactions and Director Independence

The information required by this item is incorporated herein by reference to the following sections of the Company’s definitive proxy statement, which will be filed no later than April 29, 2016: “Related Party Transactions” and “Corporate Governance Matters.”

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Item 14.        Principal Accounting Fees and Services

The information required by this item is incorporated herein by reference to the section captioned “Ratification of Selection of Independent Registered Public Accounting Firm” in the Company’s definitive proxy statement, which will be filed no later than April 29, 2016.

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PART IV

Item 15.        Exhibits and Financial Statement Schedules

The following documents are filed as a part of this report:

(1)Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements appearing on page F-1.

(2)Financial Statement Schedules

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.

(3)Exhibits

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page(s)
Management’s Report on Internal Control Over Financial Reporting	F-2
Report of Independent Registered Public Accounting Firm	F-3
Consolidated Balance Sheets at December 31, 2015 and 2014	F-4
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013	F-6
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended December  31, 2015, 2014 and 2013	F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	F-8
Notes to Consolidated Financial Statements	F-9

F-1

Management’s Report on Internal Control over Financial Reporting

Management of SandRidge Energy, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Internal control over financial reporting is a process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with generally accepted accounting principles.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015. In making this assessment, management used the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013) (the COSO criteria). Based on management’s assessment using the COSO criteria, management concluded the Company’s internal control over financial reporting was effective as of December 31, 2015.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP an independent registered public accounting firm, as stated in its report which appears herein.

/s/    JAMES D. BENNETT	/s/    JULIAN BOTT
James D. Bennett President and Chief Executive Officer	Julian Bott Executive Vice President and Chief Financial Officer

F-2

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of SandRidge Energy, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, changes in stockholders’ equity and cash flows present fairly, in all material respects, the financial position of SandRidge Energy, Inc. and its subsidiariesatDecember 31, 2015and 2014, and the results of their operations and their cash flows for each of the three years in the period endedDecember 31, 2015in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013) (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanyingManagement's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has engaged advisors to assist with a private restructuring or reorganization under Title 11 of the U.S. Bankruptcy Code in the foreseeable future, which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

	/s/ PricewaterhouseCoopers LLP
	PricewaterhouseCoopers LLP
Oklahoma City, Oklahoma
March 30, 2016

F-3

SandRidge Energy, Inc. and Subsidiaries

Consolidated Balance Sheets

	December 31,
	2015			2014
	(In thousands, except per share data)
ASSETS
Current assets
Cash and cash equivalents	$	435,588		$	181,253
Accounts receivable, net	127,387			330,077
Derivative contracts	84,349			291,414
Prepaid expenses	6,833			7,981
Other current assets	19,931			21,193
Total current assets	674,088			831,918
Oil and natural gas properties, using full cost method of accounting
Proved (includes development and project costs excluded from amortization of $34.6 million and $53.6 million at December 31, 2015 and 2014, respectively)	12,529,681			11,707,147
Unproved	363,149			290,596
Less: accumulated depreciation, depletion and impairment	(11,149,888		)	(6,359,149		)
	1,742,942			5,638,594
Other property, plant and equipment, net	491,760			576,463
Derivative contracts	—			47,003
Other assets	82,365			165,247
Total assets	$	2,991,155		$	7,259,225

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

F-4

SandRidge Energy, Inc., and Subsidiaries

Consolidated Balance Sheets—Continued

	December 31,
	2015			2014
	(In thousands, except per share data)
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	428,417		$	683,392
Derivative contracts	573			—
Asset retirement obligations	8,399			—
Deferred tax liability	—			95,843
Other current liabilities	—			5,216
Total current liabilities	437,389			784,451
Long-term debt	3,631,506			3,195,436
Asset retirement obligations	95,179			54,402
Other long-term obligations	14,814			15,116
Total liabilities	4,178,888			4,049,405
Commitments and contingencies (Note 15)
Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity
Preferred stock, $0.001 par value, 50,000 shares authorized
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015 and 2014; aggregate liquidation preference of $265,000	3			3
7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000; 3,000 shares issued and outstanding at December 31, 2014, aggregate liquidation preference of $300,000	3			3
Common stock, $0.001 par value; 1,800,000 shares authorized, 635,584 issued and 633,471 outstanding at December 31, 2015; 800,000 shares authorized, 485,932 issued and 484,819 outstanding at December 31, 2014	630			477
Additional paid-in capital	5,301,136			5,204,024
Additional paid-in capital—stockholder receivable	(1,250		)	(2,500		)
Treasury stock, at cost	(5,742		)	(6,980		)
Accumulated deficit	(6,992,697		)	(3,257,202		)
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,697,917		)	1,937,825
Noncontrolling interest	510,184			1,271,995
Total stockholders’ (deficit) equity	(1,187,733		)	3,209,820
Total liabilities and stockholders’ (deficit) equity	$	2,991,155		$	7,259,225

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

F-5

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Operations

	Years Ended December 31,
	2015			2014			2013
	(In thousands, except per share amounts)
Revenues
Oil, natural gas and NGL	$	707,434		$	1,420,879		$	1,820,278
Drilling and services	22,124			76,088			66,586
Midstream and marketing	33,809			55,658			58,304
Construction contract	—			—			23,349
Other	5,342			6,133			14,871
Total revenues	768,709			1,558,758			1,983,388
Expenses
Production	308,701			346,088			516,427
Production taxes	15,440			31,731			32,292
Cost of sales	24,394			56,155			57,118
Midstream and marketing	26,819			49,905			53,644
Construction contract	—			—			23,349
Depreciation and depletion—oil and natural gas	319,913			434,295			567,732
Depreciation and amortization—other	47,382			59,636			62,136
Accretion of asset retirement obligations	4,477			9,092			36,777
Impairment	4,534,689			192,768			26,280
General and administrative	137,715			113,991			207,920
Employee termination benefits	12,451			8,874			122,505
(Gain) loss on derivative contracts	(73,061		)	(334,011		)	47,123
Loss on settlement of contract	50,976			—			—
Loss on sale of assets	1,491			10			399,086
Total expenses	5,411,387			968,534			2,152,389
(Loss) income from operations	(4,642,678		)	590,224			(169,001		)
Other (expense) income
Interest expense	(321,421		)	(244,109		)	(270,234		)
Gain (loss) on extinguishment of debt	641,131			—			(82,005		)
Other income, net	2,040			3,490			12,445
Total other income (expense)	321,750			(240,619		)	(339,794		)
(Loss) income before income taxes	(4,320,928		)	349,605			(508,795		)
Income tax expense (benefit)	123			(2,293		)	5,684
Net (loss) income	(4,321,051		)	351,898			(514,479		)
Less: net (loss) income attributable to noncontrolling interest	(623,506		)	98,613			39,410
Net (loss) income attributable to SandRidge Energy, Inc.	(3,697,545		)	253,285			(553,889		)
Preferred stock dividends	37,950			50,025			55,525
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$	(3,735,495	)	$	203,260		$	(609,414	)
(Loss) earnings per share
Basic	$	(7.16	)	$	0.42		$	(1.27	)
Diluted	$	(7.16	)	$	0.42		$	(1.27	)
Weighted average number of common shares outstanding
Basic	521,936			479,644			481,148
Diluted	521,936			499,743			481,148

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

F-6

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders’ Equity (Deficit)

	Convertible Perpetual Preferred Stock					Common Stock					Additional Paid-In Capital			Treasury Stock			Accumulated Deficit			Non-controlling Interest			Total
	Shares		Amount			Shares		Amount
	(In thousands)
Balance at December 31, 2012	7,650		$	8		490,359		$	476		$	5,228,019		$	(8,602	)	$	(2,851,048	)	$	1,493,602		$	3,862,455
Sale of royalty trust units	—		—			—		—			7,289			—			—			21,696			28,985
Distributions to noncontrolling interest owners	—		—			—		—			—			—			—			(206,470		)	(206,470		)
Contributions from noncontrolling interest owners	—		—			—		—			—			—			—			1,579			1,579
Purchase of treasury stock	—		—			—		—			—			(30,126		)	—			—			(30,126		)
Retirement of treasury stock	—		—			—		—			(30,126		)	30,126			—			—			—
Stock purchases, net of distributions - retirement plans	—		—			(99	)	—			(267		)	(168		)	—			—			(435		)
Stock-based compensation	—		—			—		—			88,397			—			—			—			88,397
Stock-based compensation excess tax provision	—		—			—		—			(4		)	—			—			—			(4		)
Payment received on shareholder receivable	—		—			—		—			1,250			—			—			—			1,250
Issuance of restricted stock awards, net of cancellations	—		—			30		7			(7		)	—			—			—			—
Net (loss) income	—		—			—		—			—			—			(553,889		)	39,410			(514,479		)
Convertible perpetual preferred stock dividends	—		—			—		—			—			—			(55,525		)	—			(55,525		)
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
Sale of royalty trust units	—		—			—		—			4,091			—			—			18,028			22,119
Distributions to noncontrolling interest owners	—		—			—		—			—			—			—			(193,807		)	(193,807		)
Purchase of treasury stock	—		—			—		—			—			(6,373		)	—			—			(6,373		)
Retirement of treasury stock	—		—			—		—			(6,373		)	6,373			—			—			—
Stock distributions, net of purchases - retirement plans	—		—			206		—			(1,781		)	1,790			—			—			9
Stock-based compensation	—		—			—		—			23,665			—			—			—			23,665
Stock-based compensation excess tax benefit	—		—			—		—			14			—			—			—			14
Payment received on shareholder receivable	—		—			—		—			1,250			—			—			—			1,250
Issuance of restricted stock awards, net of cancellations	—		—			3,311		3			(3		)	—			—			—			—
Acquisition of ownership interest	—		—			—		—			(2,074		)	—			—			(656		)	(2,730		)
Repurchase of common stock	—		—			(27,411	)	(27		)	(111,800		)	—			—			—			(111,827		)
Conversion of 6% preferred stock	(2,000	)	(2		)	18,423		18			(16		)	—			—			—			—
Net income	—		—			—		—			—			—			253,285			98,613			351,898
Convertible perpetual preferred stock dividends	—		—			—		—			—			—			(50,025		)	—			(50,025		)
Balance at December 31, 2014	5,650		6			484,819		477			5,201,524			(6,980		)	(3,257,202		)	1,271,995			3,209,820
Distributions to noncontrolling interest owners	—		—			—		—			—			—			—			(138,305		)	(138,305		)
Purchase of treasury stock	—		—			—		—			—			(2,428		)	—			—			(2,428		)
Retirement of treasury stock	—		—			—		—			(2,428		)	2,428			—			—			—
Stock distributions, net of purchases - retirement plans	—		—			(1,000	)	—			(916		)	1,238			—			—			322
Stock-based compensation	—		—			—		—			21,123			—			—			—			21,123
Payment received on shareholder receivable	—		—			—		—			1,250			—			—			—			1,250
Issuance of restricted stock awards, net of cancellations	—		—			1,514		5			(5		)	—			—			—			—
Common stock issued for debt	—		—			120,881		121			63,178			—			—			—			63,299
Conversion of preferred stock to common stock	(230	)	—			2,968		3			(3		)	—			—			—			—
Net loss	—		—			—		—			—			—			(3,697,545		)	(623,506		)	(4,321,051		)
Convertible perpetual preferred stock dividends	—		—			24,289		24			16,163			—			(37,950		)	—			(21,763		)
Balance at December 31, 2015	5,420		$	6		633,471		$	630		$	5,299,886		$	(5,742	)	$	(6,992,697	)	$	510,184		$	(1,187,733	)

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

F-7

SandRidge Energy, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

	Years Ended December 31,
	2015			2014			2013
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(4,321,051	)	$	351,898		$	(514,479	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	367,295			493,931			629,868
Accretion of asset retirement obligations	4,477			9,092			36,777
Impairment	4,534,689			192,768			26,280
Debt issuance costs amortization	11,884			9,425			10,091
Amortization of discount, net of premium, on long-term debt	3,130			529			1,036
(Gain) loss on extinguishment of debt	(641,131		)	—			82,005
Write off of debt issuance costs	7,108			—			—
Deferred income tax provision	—			—			3,842
Loss on long-term debt derivatives	10,377			—			—
Cash paid for early conversion of convertible notes	(32,741		)	—			—
(Gain) loss on derivative contracts	(73,061		)	(334,011		)	47,123
Cash received (paid) on settlement of derivative contracts	327,702			11,796			(5,879		)
Loss on settlement of contract	50,976			—			—
Cash paid on settlement of contract	(24,889		)	—			—
Loss on sale of assets	1,491			10			399,086
Stock-based compensation	18,380			19,994			85,270
Other	1,351			407			3,929
Changes in operating assets and liabilities increasing (decreasing) cash
Receivables	201,907			(63,492		)	90,048
Costs in excess of billings	—			—			11,229
Prepaid expenses	1,148			9,549			(7,934		)
Other current assets	12,710			3,164			(3,269		)
Other assets and liabilities, net	2,239			(1,132		)	5,777
Accounts payable and accrued expenses	(86,470		)	(66,492		)	101,453
Asset retirement obligations	(3,984		)	(16,322		)	(133,623		)
Net cash provided by operating activities	373,537			621,114			868,630
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(879,201		)	(1,553,332		)	(1,496,731		)
Acquisitions of assets	(216,943		)	(18,384		)	(17,028		)
Proceeds from sale of assets	56,504			714,475			2,584,115
Net cash (used in) provided by investing activities	(1,039,640		)	(857,241		)	1,070,356
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	2,065,000			—			—
Repayments of borrowings	(939,466		)	—			(1,115,500		)
Premium on debt redemption	—			—			(61,997		)
Debt issuance costs	(53,244		)	(3,947		)	(91		)
Proceeds from the sale of royalty trust units	—			22,119			28,985
Noncontrolling interest distributions	(138,305		)	(193,807		)	(206,470		)
Noncontrolling interest contributions	—			—			1,579
Acquisition of ownership interest	—			(2,730		)	—
Stock-based compensation excess tax benefit	—			14			(4		)
Purchase of treasury stock	(3,535		)	(8,702		)	(32,976		)
Repurchase of common stock	—			(111,827		)	—
Dividends paid—preferred	(11,262		)	(55,525		)	(55,525		)
Payment received on shareholder receivable	1,250			1,250			1,250
Cash (paid) received on settlement of financing derivative contracts	—			(44,128		)	6,660
Net cash provided by (used in) financing activities	920,438			(397,283		)	(1,434,089		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	254,335			(633,410		)	504,897
CASH AND CASH EQUIVALENTS, beginning of year	181,253			814,663			309,766
CASH AND CASH EQUIVALENTS, end of year	$	435,588		$	181,253		$	814,663

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

F-8

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Nature of Business. SandRidge Energy, Inc. is an energy 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 the Rockies in Colorado. The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater gathering and disposal system, an electrical transmission system and a drilling and related oilfield services business.

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

Going Concern. The Company depends on cash flows from operating activities and, as necessary and available, borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Additionally, the Company historically has used 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.

The market price for oil, natural gas and natural gas liquids (“NGLs”) decreased significantly beginning in the fourth quarter of 2014, continuing throughout 2015, and into 2016. The decrease in the market price for production directly reduces the Company’s cash flow from operations and indirectly impacts its other potential sources of funds described above. As discussed in Note 22, the Company borrowed all of its remaining available capacity under the senior credit facility in January 2016 and in March 2016, the lenders under the senior credit facility elected to reduce the borrowing base to $340.0 million. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties. Lower market prices for production may result in further reductions to the borrowing base under the senior credit facility or higher borrowing costs from other potential sources of financing as the Company’s borrowing capacity and borrowing costs are generally related to the value of the Company’s estimated proved reserves. The weakness in pricing may also impact the Company’s ability to negotiate asset monetizations at acceptable prices.

As a result of the impacts to the Company’s financial position resulting from declining industry conditions and in consideration of the substantial amount of long-term debt outstanding, the Company has engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its financial position or complete any strategic transactions. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern as it is currently structured.

As a result, the report of the Company’s independent registered public accounting firm that accompanies these consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern, which under the terms of the senior credit facility may result in an event of default. If the Company does not obtain a waiver of this requirement or otherwise cure this event within 30 calendar days of the issuance of these financial statements, the lenders under the senior credit facility will be able to accelerate maturity of the debt. Any acceleration of the obligations under the senior credit facility would result in a cross-default and potential acceleration of the maturity of the Company’s other outstanding long-term debt. These defaults create additional uncertainty associated with the Company’s ability to repay its outstanding long-term debt obligations as they become due and further reinforces the substantial doubt over the Company’s ability to continue as a going concern.

The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern.

F-9

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE and the significance of the variable interest, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements. In addition to the VIEs that the Company consolidates, until October 2015, the Company also held a variable interest in another VIE that it did not consolidate 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.

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

Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; cash flow estimates used in the valuations of guarantees; impairment tests of long-lived assets; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.

Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the exploration, production and treating services for oil and natural gas. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts.

Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements.

Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5.

F-10

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates. Additionally, the Company has derivatives related to its 8.75% Senior Secured Notes due 2020 (“Senior Secured Notes”) and its 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, “Convertible Senior Unsecured Notes”) that are recorded at fair value each reporting period. Refer to Notes 5 and 13 for further information on derivatives associated with the Company’s long-term debt.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 13 for further discussion of the Company’s derivatives.

Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized internal costs of $45.1 million, $55.4 million and $74.7 million to the full cost pool during the years ended December 31, 2015, 2014 and 2013, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.

F-11

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.

Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If an asset or asset group is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. See Note 8 for further discussion of impairments.

Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During 2015, 2014 and 2013, interest of approximately $10.8 million, $14.7 million and $11.7 million, respectively, was capitalized on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally, interest of $3.3 million, $5.0 million and $4.9 million was capitalized in 2015, 2014 and 2013, respectively, on midstream and corporate assets which were under construction.

Debt Issuance Costs. The Company amortizes debt issuance costs related to its long-term debt as interest expense over the scheduled maturity period of the related debt. The Company includes unamortized debt issuance costs in other assets in the consolidated balance sheets. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.

Investments. Investments in marketable equity securities have been designated as available for sale and measured at fair value pursuant to the fair value option which requires unrealized gains and losses be reported in earnings.

Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 14 for further discussion of the Company’s asset retirement obligations.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $1.5 million and $1.4 million at December 31, 2015 and 2014, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

F-12

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

The Company accounted for its construction contract, discussed in Note 11, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract losses are recorded at the time it is determined that a loss will be incurred. Contract gains, if any, are recorded upon substantial completion of the construction project.

The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized at the time mobilization services are performed.

In general, natural gas purchased and sold by the midstream business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, since the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold.

Share-Based Compensation. The Company may grant restricted stock awards to members of its Board of Directors (the “Board”) and its employees. Such awards and the related stock-based compensation cost are measured based on the calculated fair value of the award on the grant date. The expense, net of estimated forfeitures, is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award.

The Company grants restricted stock units to members of the Board and its employees. Such awards are settled in cash, shares of Company common stock or a combination of common stock and cash. Restricted stock units vest over a maximum four-year period from the grant date and are valued based upon the Company’s stock price at each period end.

To the extent stock-based compensation cost relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statements of operations. The related excess tax benefit received upon vesting of restricted stock, if any, is reflected in the consolidated statements of cash flows as a financing activity. The related excess tax expense due upon vesting of restricted stock, if any, is reflected in the consolidated statements of cash flows as an operating activity.

Performance Unit Compensation. The Company awards performance units and performance share units, which contain a market-based performance component with cash settlement at the end of the performance period, to certain members of senior management. The Company recognizes a liability and expense for performance unit compensation for the portion earned over the requisite service period in an amount equal to the fair value of the performance units granted. Changes in the fair value of the units for which the service requirement has been met are recognized as compensation expense with a corresponding adjustment to the liability. To the extent performance unit compensation cost relates to those directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statements of operations.

Advertising Costs. The Company expenses advertising costs as incurred. Advertising and promotional costs were $0.7 million, $1.3 million, and $5.1 million, respectively, during the years ended December 31, 2015, 2014 and 2013.

Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.

The Company has elected an accounting policy in which interest and penalties on income taxes are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.

Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding,

F-13

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested restricted stock awards and restricted share units, using the treasury method, and convertible preferred stock and convertible senior notes, using the if-converted method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants is assumed to be used to repurchase shares at the average market price. Under the if-converted method, the Company assumes the conversion of the preferred stock or convertible senior notes to common stock and determines if it is more dilutive than including the preferred stock dividends or expense associated with the convertible senior notes, respectively, in the computation of income available to common stockholders. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 20 for the Company’s earnings per share calculation.

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 15 for discussion of the Company’s commitments and contingencies.

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

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

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. See Note 23 for information regarding the Company’s major customers. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect the Company’s ability to sell the oil, natural gas and NGLs it produces.

Recent Accounting Pronouncements. In April 2014, the financial accounting standards board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”, which amends the definition of a discontinued operations to elevate the threshold for a disposal transaction to qualify as a discontinued operation and requires entities to provide additional disclosures for disposal transactions that do not meet the discontinued operations criteria. The guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The guidance was adopted January 1, 2015 and had no impact for the year ended December 31, 2015.

In November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which requires the classification of all deferred tax assets and liabilities as non-current. The guidance is effective on either a prospective or retrospective basis for periods beginning after December 15, 2016, with early adoption permitted. The Company elected to adopt this guidance on a prospective basis on December 31, 2015, and as such, did not retrospectively adjust prior periods. Since the Company’s deferred tax assets and liabilities are equal and offsetting after including the effect of the valuation allowance, adoption

F-14

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

of the guidance resulted in the elimination, for presentation purposes, of a non-current deferred tax asset and a current deferred tax liability on the accompanying consolidated balance sheet at December 31, 2015.

Recent Accounting Pronouncements Not Yet Adopted. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Certain of the provisions also amend or supersede existing guidance applicable to the recognition of a gain or loss on transfers of nonfinancial assets that are not an output of an entity’s ordinary activities, including sales of property, plant and equipment and real estate. In August, 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which defers the effective date of ASU 2014-09 to annual periods beginning after December 15, 2017, and interim periods within that reporting period. Early adoption is permitted, and either a full retrospective or modified approach may be used for adoption. The Company is currently evaluating the effect, if any, that the updated standard will have on its consolidated financial statements and related disclosures.

In August 2014, the FASB issued ASU 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The Company evaluated the effect of the guidance and it will have no impact on its related disclosures.

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

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

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-06, “Contingent Put and Call Options in Debt Instruments” which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts, which is one of the criteria for bifurcating an embedded derivative. The amendments eliminate diversity in practice in assessing embedded contingent call (put) options in debt instruments. The guidance requires adoption by application of a modified retrospective approach to existing and future debt instruments effective for fiscal years after December 15, 2016, including interim periods within those years.  Early adoption is permitted. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

F-15

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

2. Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Years Ended December 31,
	2015			2014			2013
	(In thousands)
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(296,386	)	$	(235,793	)	$	(274,850	)
Cash (paid) received for income taxes	$	(88	)	$	1,928		$	(4,610	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	—		$	—		$	(255,000	)
Change in accrued capital expenditures	$	177,586		$	(55,557	)	$	72,848
Equity issued for debt	$	(63,299	)	$	—		$	—
Preferred stock dividends paid in common stock	$	(16,188	)	$	—		$	—
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$	(50,310	)	$	—		$	—

3. Acquisitions and Divestitures

2015 Acquisitions

Acquisition of Piñon Gathering Company, LLC. In October 2015, the Company acquired all of the assets of and terminated a gathering agreement with Piñon Gathering Company, LLC (“PGC’) for $48.0 million in cash and $78.0 million principal amount of newly issued 8.75% Senior Secured Notes due 2020 (“PGC Senior Secured Notes”). PGC owns approximately 370 miles of gathering lines supporting the natural gas production from the Company's Piñon field in the West Texas Overthrust (“WTO”). The transaction resulted in the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. The fair value of the consideration paid by the Company, including discount attributable to the PGC Senior Secured Notes, was approximately $98.3 million and was allocated on a fair value basis between the assets acquired (approximately $47.3 million) and a loss on the termination of the gathering contract (approximately $51.0 million). See Note 4 for further discussion of the gathering agreement with PGC.

Acquisition of Rockies Properties. In December 2015, the Company acquired approximately 135,000 net acres in the North Park Basin in the Rockies, in Jackson County, Colorado. The Company paid approximately $191.1 million in cash, including post-closing adjustments, and received $3.1 million from the seller for overriding royalty interests. Also included in the acquisition were working interests in 16 wells previously drilled on the acreage.

2014 Divestiture

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 21 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 December 31, 2014, the fair value of the guarantees was approximately $5.1 million. See Note 5 for additional discussion of the determination of the guarantee’s fair value. The guarantee did not include a limit on the potential future payments for which the Company could be obligated; however, Fieldwood agreed to indemnify the Company for any costs it incurred as a result of the guarantee and to use its best efforts to pay any amounts sought from the Company by the Bureau of Ocean Energy Management (“BOEM”) that arose prior to the expiration of the guarantee. The Company did not incur any costs as a result of this guarantee and was released from the obligation during the third quarter of 2015. Additionally, Fieldwood maintained, for a period of up to one year from the

F-16

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

closing date, restricted deposits held in escrow for plugging and abandonment obligations associated with the Gulf Properties. In the first quarter of 2015, the Company received its share of such deposits, net of any amounts payable to Fieldwood, or $12.0 million, in accordance with the terms of the sale.

The following table presents revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties included in the accompanying consolidated statements of operations for the years ended December 31, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2014(1)		2013
Revenues	$	90,920	$	627,236
Expenses	$	63,674	$	491,991

____________________

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

2013 Divestiture

Sale of Permian Properties. On February 26, 2013, the Company sold its oil and natural gas properties in the Permian Basin area of west Texas, excluding the assets associated with the SandRidge Permian Trust area of mutual interest (the “Permian Properties”) for $2.6 billion, including certain post-closing adjustments that were finalized in the third quarter of 2013. 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. The loss is included in loss on sale of assets in the accompanying consolidated statement of operations for the year ended December 31, 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 consolidated statement of operations for the year ended December 31, 2013.

The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying consolidated statement of operations for the year ended December 31, 2013 (in thousands):

	Year Ended December 31, 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.

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

F-17

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

that could potentially be significant to the Royalty Trusts. As a result, the Company consolidates the activities of the Royalty Trusts. The common units of the Royalty Trusts owned by third parties are reflected as noncontrolling interest in the consolidated financial statements.

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

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

 ____________________

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

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

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

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

Royalty Interests. The Royalty Trusts own royalty interests in oil and natural gas wells that were either (i) conveyed to the Royalty Trusts by SandRidge concurrent with the closing of each Royalty Trust’s initial public offering or (ii) drilled within a defined area of mutual interest during a specified period of time as discussed further below. Pursuant to the agreements governing the Royalty Trusts, the Mississippian Trust I will terminate in 2030 and the Permian Trust and Mississippian Trust II will terminate in 2031. Upon termination, 50% of the royalty interests of each Royalty Trust will automatically revert to the Company, and the remaining 50% will be sold, with the proceeds distributed to the Royalty Trust unitholders.

Drilling Obligations. The Company and one of its wholly owned subsidiaries entered into a development agreement with each Royalty Trust upon conveyance of the royalty interests by the Company that obligated the Company to drill, or cause to be drilled, a specified number of wells which are also subject to the royalty interests within respective areas of mutual interest by a specified date. One of the Company’s wholly owned subsidiaries also granted to each Royalty Trust a lien on the Company’s interests in the properties where the development wells were to be drilled in order to secure the estimated amount of drilling costs for the Royalty Trust’s interests in the wells. The total amount that may be recovered by each Royalty Trust under its respective lien was proportionately reduced as the Company has drilled and completed the associated development wells. The Company fulfilled its drilling obligation to the Mississippian Trust I in the second quarter of 2013, to the Permian Trust in the fourth quarter of 2014 and to the Mississippian Trust II in the first quarter of 2015 and the related liens were automatically released.

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

F-18

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Quarterly distributions declared and paid by the Royalty Trusts during the years ended December 31, 2015, 2014 and 2013 as follows (in thousands):

	Year Ended December 31,
	2015(1)		2014(2)		2013(3)
Total distributions	$	158,632	$	234,326	$	299,674
Distributions to third-party unitholders	$	138,305	$	193,807	$	206,470

____________________

(1) Subordination thresholds were not met for the Permian Trust and Mississippian Trust II’s distributions for the year ended December 31, 2015, resulting in reduced distributions to the Company on its subordinated units for this period.

(2) Subordination thresholds were not met for the Mississippian Trust I’s first or second quarter 2014 distributions, the Permian Trust’s second, third or fourth quarter 2014 distributions or for the Mississippian Trust II’s distributions for the year ended December 31, 2014, resulting in reduced distributions to the Company on its subordinated units for these periods.

(3) Subordination thresholds were not met for the Mississippian Trust I’s second, third or fourth quarter 2013 distributions, the Permian Trust’s second quarter 2013 distribution or for the Mississippian Trust II’s fourth quarter 2013 distribution, resulting in reduced distributions to the Company on its subordinated units for these periods.

See Note 22 for discussion of the Royalty Trusts’ distributions announced in January 2016.

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

Loan Commitment. Pursuant to the agreements governing the Royalty Trusts, the Company 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 the Company 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 December 31, 2015 or 2014.

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

Derivatives Agreements. The Company had a derivatives agreement with each Royalty Trust, pursuant to which the Company provided to the Royalty Trust the economic effects of certain of the Company’s derivative contracts covering production through December 31, 2015 for the Mississippian Trust I and the Mississippian Trust II and through March 31, 2015 for the Permian Trust. These agreements expired upon expiration of the underlying derivative contracts.

See Note 13 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

F-19

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Assets and Liabilities. Each Royalty Trust’s assets can be used to settle only that Royalty Trust’s obligations and not other obligations of the Company or another Royalty Trust. The Royalty Trusts’ creditors have no contractual recourse to the general credit of the Company. Although the Royalty Trusts are included in the Company’s consolidated financial statements, the Company’s legal interest in the Royalty Trusts’ assets is limited to its ownership of the Royalty Trusts’ units. At December 31, 2015 and 2014, $510.2 million and $1.3 billion, respectively, of noncontrolling interest in the accompanying consolidated balance sheets were attributable to the Royalty Trusts. The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying consolidated balance sheets at December 31, 2015 and 2014 consisted of the following (in thousands):

	December 31,
	2015			2014
Cash and cash equivalents(1)	$	7,824		$	9,387
Accounts receivable	4,457			17,660
Derivative contracts	—			6,589
Total current assets	12,281			33,636
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion and impairment(3)	(1,248,957		)	(284,094		)
	76,985			1,041,848
Total assets	$	89,266		$	1,075,484
Accounts payable and accrued expenses	$	1,060		$	2,852
Total liabilities	$	1,060		$	2,852

____________________

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

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

(3) Includes cumulative full cost ceiling limitation impairment of $976.2 million and $42.3 million at December 31, 2015 and 2014, respectively.

See Note 15 for discussion of the Company’s legal proceedings to which the Mississippian Trust I and Mississippian Trust II are also parties.

Sales of Common Units. During the years ended December 31, 2014 and 2013, the Company sold Royalty Trust common units it owned in transactions exempt from registration pursuant to Rule 144 under the Securities Act for proceeds of approximately $22.1 million and $29.0 million, respectively. The unit sales were accounted for as equity transactions with no gain or loss recognized. The Company continued to be the primary beneficiary of the Royalty Trusts after consideration of these transactions and continues to consolidate the activities of the Royalty Trusts.

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 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 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.

F-20

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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

PGC’s assets consist of approximately 370 miles ofgathering lines that support the Company’s production in the Piñon field in West Texas. The Company acquired PGC in October 2015, and upon acquisition, terminated a gas gathering and operations and maintenance agreement with PGC, which required the Company to compensate PGC for any throughput shortfalls below a required minimum volume through June 30, 2029. By guaranteeing a minimum throughput, the Company absorbed the risk that lower than projected volumes would be gathered by the PGC’s gathering system. Therefore, prior to its acquisition, PGC was a VIE. Other than as required under the gas gathering and operations and maintenance agreements, the Company did not provide any support to PGC. While the Company operated the assets of PGC as directed under the operations and management agreement, the member and managers of PGC had the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company did not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company was not the primary beneficiary of PGC and, therefore, and did not consolidate the results of PGC’s activities into the Company’s financial statements prior to its acquisition. As a wholly owned subsidiary, PGC is no longer considered a VIE for reporting purposes.

Amounts due from and due to PGC as of December 31, 2014 included in the accompanying consolidated balance sheet are as follows (in thousands):

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

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).

F-21

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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

Level 1 Fair Value Measurements

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

Level 2 Fair Value Measurements

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

Mandatory Prepayment Feature - PGC Senior Secured Notes. In conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015, the Company issued the PGC Senior Secured Notes with a $78.0 million principal value. These notes bear payment terms identical to and are secured by the same assets as the 8.75% Senior Secured Notes due 2020 issued by the Company in June 2015 as discussed in Note 12. The 8.75% Senior Secured Notes due 2020 issued in June 2015 and PGC Senior Secured Notes (collectively, “Senior Secured Notes”) will mature on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019. The issuance of the PGC Senior Secured Notes at a substantial discount, as discussed in Note 12 and Note 13, resulted in the treatment of the mandatory prepayment feature contained in those notes as an embedded derivative that meets the criteria to be bifurcated from its host contract, the PGC Senior Secured Notes, and accounted for separately from those notes. The mandatory prepayment feature contained in the PGC Senior Secured Notes is recorded at fair value each reporting period based upon values determined through the use of discounted cash flow models of the PGC Senior Secured Notes both (i) with the mandatory prepayment feature and (ii) excluding the mandatory prepayment feature.

Level 3 Fair Value Measurements

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

Unobservable Input	Range							Weighted Average			Fair Value
	(Price per Mcf)										(In thousands)
December 31, 2015
Natural gas basis differential forward curve	$	(0.06	)	–	$	(0.28	)	$	(0.22	)	$	(1,748	)
December 31, 2014
Natural gas basis differential forward curve	$	(0.03	)	–	$	(0.38	)	$	(0.29	)	$	350

F-22

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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

The fair values of the holder conversion features were determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) recovery rate, (iv) hazard rate and (v) expected volatility. The significant unobservable input used in the fair value measurement of the conversion features is the hazard rate, an estimate of default probability. Significant increases (decreases) in the hazard rate could result in significantly (lower) higher fair value measurement.The significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion features atDecember 31, 2015are included in the table below.

Unobservable Input	Range					Weighted Average		Fair Value
								(In thousands)
December 31, 2015
Long-term debt conversion feature hazard rate	114.0	%	–	135.2	%	119.2	%	$	29,355

See further discussion of the Convertible Senior Unsecured Notes at Note 12.

Guarantees. As discussed in Note 3, the Company guaranteed on Fieldwood’s behalf certain plugging and abandonment obligations associated with the Gulf Properties from the date of closing until the Company was released from the guarantee in the third quarter of 2015. The fair value of this guarantee was based on the present value of estimated future payments for plugging and abandonment obligations associated with the Gulf Properties, adjusted for the cumulative probability of Fieldwood’s default prior to the Company’s release by the BOEM from its obligation under the guarantee (3.71% at December 31, 2014). The discount and probability of default rates were based upon inputs that are readily available in the public market, such as historical option adjusted spreads of the Company’s senior notes, which are publicly traded, and historical default rates of publicly traded companies with credit ratings similar to Fieldwood. The significant unobservable input used in the fair value measurement of the guarantees was the estimate of future payments for plugging and abandonment of approximately $372.0 million, which was developed based upon third-party quotes and then-current actual costs. Significant increases (decreases) in the estimate of these payments could have resulted in a significantly higher (lower) fair value measurement.

Fair Value - Recurring Measurement Basis

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

December 31, 2015

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	85,524	$	—	$	(1,175	)	$	84,349
Investments	10,106		—		—		—			10,106
	$	10,106	$	85,524	$	—	$	(1,175	)	$	94,455
Liabilities
Commodity derivative contracts	$	—	$	—	$	1,748	$	(1,175	)	$	573
Long-term debt holder conversion feature	—		—		29,355		—			29,355
Mandatory prepayment feature - PGC Senior Secured Notes	—		2,941		—		—			2,941
	$	—	$	2,941	$	31,103	$	(1,175	)	$	32,869

F-23

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

December 31, 2014

	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	338,067	$	350	$	—	$	338,417
Investments	11,106		—		—		—		11,106
	$	11,106	$	338,067	$	350	$	—	$	349,523
Liabilities
Guarantee	$	—	$	—	$	5,104	$	—	$	5,104
	$	—	$	—	$	5,104	$	—	$	5,104

____________________

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

Level 3 - Commodity Derivative Contracts. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for commodity derivative contracts during the years ended December 31, 2015, 2014 and 2013 (in thousands):

Level 3 Fair Value Measurements - Commodity Derivative Contracts	2015			2014		2013
Beginning balance	$	350		$	—	$	(512	)
Loss on commodity derivative contracts	(350		)	—		(133		)
Purchases	(1,748		)	350		—
Settlements paid	—			—		645
Level 3 commodity derivative contracts at December 31	$	(1,748	)	$	350	$	—

Losses due to changes in fair value of the Company’s Level 3 commodity derivative contracts have been included in (gain) loss on derivative contracts in the accompanying consolidated statements of operations. There were no outstanding Level 3 commodity derivative contracts at December 31, 2013. See Note 13 for further discussion of the Company’s derivative contracts.

Level 3 - Long-Term Debt Holder Conversion Feature. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for long-term debt holder conversion features during the year ended December 31, 2015 (in thousands):

Level 3 Fair Value Measurements - Long-Term Debt Holder Conversion Feature
Beginning balance	$	—
Issuances	31,200
Gain on derivative holder conversion feature	10,198
Conversions	(12,043		)
Ending balance	$	29,355

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

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

Level 3 Fair Value Measurements - Guarantee	2015			2014
Beginning balance	$	5,104		$	—
Issuances	—			9,446
Loss on guarantee	—			(4,342		)
Settlements	(5,104		)	—
Ending balance	$	—		$	5,104

While in effect, the fair value of the guarantee was determined quarterly with changes in fair value recorded as an adjustment to the full cost pool. See Note 3 for discussion of the sale of the Gulf Properties. The fair value of the guarantees as of December 31, 2014 is included in other current liabilities in the accompanying consolidated balance sheet.

F-24

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the years ended December 31, 2015, 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 - Long-Term Debt

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

	December 31, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
8.75% Senior Secured Notes due 2020(1)	$	403,098	$	1,301,098	$	—	$	—
Senior Unsecured Notes
8.75% Senior Notes due 2020(2)	$	39,740	$	392,666	$	303,750	$	445,402
7.5% Senior Notes due 2021(3)	$	79,812	$	759,711	$	752,000	$	1,178,486
8.125% Senior Notes due 2022	$	57,749	$	527,737	$	472,500	$	750,000
7.5% Senior Notes due 2023(4)	$	58,799	$	541,572	$	519,750	$	821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022(5)	$	44,199	$	82,294	$	—	$	—
7.5% Convertible Senior Notes due 2023(6)	$	15,125	$	26,428	$	—	$	—

___________________

(1) Carrying value includes mandatory prepayment feature liabilities with fair value of $2,941 and is net of $29,842 discount at December 31, 2015.

(2) Carrying value is net of $3,269 and $4,598 discount at December 31, 2015 and 2014, respectively.

(3) Carrying value includes a premium of $1,944 and $3,486 at December 31, 2015 and 2014, respectively.

(4) Carrying value is net of $1,989 and $3,452 discount at December 31, 2015 and 2014, respectively.

(5) Carrying value includes holder conversion feature liabilities with fair value of $21,874 and is net of $180,751 discount at December 31, 2015.

(6) Carrying value includes holder conversion feature liabilities with fair value of $7,481 and is net of $59,549 discount at December 31, 2015.

See Note 12 for discussion of the Company’s long-term debt.

Fair Value of Non-Financial Assets and Liabilities

See Note 8 for discussion of the Company’s impairment valuations.

F-25

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

6. Accounts Receivable

A summary of accounts receivable is as follows (in thousands):

	December 31,
	2015			2014
Oil, natural gas and NGL sales	$	61,140		$	139,848
Joint interest billing	60,403			170,937
Oil and natural gas services	2,417			21,436
Other	8,274			4,939
	132,234			337,160
Less: allowance for doubtful accounts	(4,847		)	(7,083		)
Total accounts receivable, net	$	127,387		$	330,077

The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2015			2014			2013
Beginning balance	$	7,083		$	11,061		$	5,635
Additions charged to costs and expenses(1)	1,320			818			5,497
Deductions(2)	(3,556		)	(4,796		)	(71		)
Ending balance	$	4,847		$	7,083		$	11,061

____________________

(1) Includes $2.7 million of allowance for receivables deemed uncollectible at December 31, 2013, primarily due to the bankruptcy status of customers.

(2) Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2015 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement, and deductions in 2014 are related to the sale of the Gulf Properties.

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Notes to Consolidated Financial Statements - (Continued)

7. Property, Plant and Equipment

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

	December 31,
	2015			2014
Oil and natural gas properties
Proved(1)	$	12,529,681		$	11,707,147
Unproved	363,149			290,596
Total oil and natural gas properties	12,892,830			11,997,743
Less accumulated depreciation, depletion and impairment	(11,149,888		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	1,742,942			5,638,594
Land	14,260			16,300
Non-oil and natural gas equipment(2)	373,687			602,392
Buildings and structures(3)	227,673			263,191
Total	615,620			881,883
Less accumulated depreciation and amortization	(123,860		)	(305,420		)
Other property, plant and equipment, net	491,760			576,463
Total property, plant and equipment, net	$	2,234,702		$	6,215,057

____________________

(1) Includes cumulative capitalized interest of approximately $48.9 million and $38.1 million at December 31, 2015 and 2014, respectively.

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

(3) Includes cumulative capitalized interest of approximately $20.4 million and $17.1 million at December 31, 2015 and 2014, respectively.

Accumulated depreciation, depletion and impairment for oil and natural gas properties includes cumulative full cost ceiling limitation impairment of $8.2 billion and $3.7 billion at December 31, 2015 and 2014, respectively. During the years ended December 31, 2015 and 2014, the Company reduced the net carrying value of its oil and natural gas properties by $4.5 billion and $164.8 million, respectively, as a result of its quarterly full cost ceiling analyses. There was no full cost ceiling impairment during the year ended December 31, 2013. See Note 8 for discussion of impairment of other property, plant and equipment.

The average rates used for depreciation and depletion of oil and natural gas properties were $10.67 per Boe in 2015, $15.00 per Boe in 2014 and $16.81 per Boe in 2013.

During the second and fourth quarters of 2015, the Company classified drilling and oilfield services assets having net book values of approximately $20.0 million and $16.0 million, respectively, as held for sale as a result of the Company’s decisions to discontinue substantially all drilling and oilfield services operations first in the Permian region and then companywide. The Company disposed of certain drilling and oilfield services assets held for sale during the third quarter of 2015 and recorded a loss on sale of assets of $3.5 million for the year ended December 31, 2015. The Company expects to dispose of the remaining assets classified as held for sale at December 31, 2015 prior to the fourth quarter of 2016.

Drilling Carry Commitments

During the years ended December 31, 2014 and 2013, the Company was party to 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 year ended December 31, 2014, and a combined $408.0 million for both Atinum MidCon I, LLC’s (“Atinum”) and Repsol’s drilling carries during the year ended December 31, 2013, which reduced the Company’s capital expenditures for the respective periods. Repsol fully funded its carry commitment in the third quarter of 2014, and the carry commitment from Atinum was fully utilized during the third quarter of 2013.

Under the original 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

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Notes to Consolidated Financial Statements - (Continued)

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. Under the terms of the amended agreement, the Company agreed to carry Repsol’s future drilling and completion costs in the amount of $1.0 million for each well of the 484 commitment that it did not drill, up to a maximum of $75.0 million in carry costs.  As of May 31, 2015, the Company had drilled 453 net wells under this arrangement. As a result, the Company will carry a portion of Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled in the future in the area of mutual interest. The Company incurred approximately $16.1 million in costs toward this obligation during the year ended December 31, 2015. Other than the above, the Company has no carry or drilling obligations to Repsol.

Costs Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2015 (in thousands):

			Year Cost Incurred
	Total		2015		2014		2013		2012 and Prior
Property acquisition	$	362,803	$	197,849	$	70,304	$	14,011	$	80,639
Exploration(1)	34,988		10,698		6,263		17,688		339
Total costs incurred	$	397,791	$	208,547	$	76,567	$	31,699	$	80,978

____________________

(1) Includes $34.7 million of pipe inventory costs incurred ($10.5 million in 2015, $6.2 million in 2014 and $18.0 million in 2013 and prior years).

The Company expects to complete the majority of the evaluation activities within 10 years from the applicable date of acquisition, contingent on the Company’s capital expenditures and drilling program. In addition, the Company’s internal engineers evaluate all properties on at least an annual basis.

8. Impairment

Property, Plant and Equipment

As deemed necessary based on events in 2015, 2014 and 2013, the Company analyzed various property, plant and equipment for impairment. Estimated fair values of these assets were determined using a combination of the discounted cash flow method, recent offers from third-party purchasers or prices of comparable assets with consideration of current market conditions. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5.

Oil and Natural Gas Properties. The Company incurred impairments of $4.5 billion and $164.8 million for the years ended December 31, 2015 and 2014, respectively, due to a full cost ceiling limitations. The impairments recorded in 2015 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued in 2015. The impairment in 2014 resulted 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.

Drilling Assets. During 2015, the Company evaluated certain drilling assets for impairment based on the Company’s plans for their future use. As a result of these evaluations, the Company recorded impairments of $37.6 million for the year ended December 31, 2015. During the fourth quarter of 2015, the Company classified drilling and oilfield services assets having a net book value of approximately $16.0 million, as held for sale, which were included in other current assets in the accompanying consolidated balance sheet at December 31, 2015. See Note 7 for additional discussion of assets held for sale.

As a result of the Company’s fulfillment of its drilling obligation with the Permian Trust and the downward trend in oil prices that began in the second half of 2014, demand for the Company’s drilling and oilfield services in the Permian region declined significantly. At December 31, 2014, the Company determined the future use of its drilling and oilfield services assets in this region was limited and recorded an impairment of $24.3 million on these assets.

During 2014 and 2013, the Company committed to plans to sell various drilling assets. The net book value of these drilling assets was adjusted to fair value, resulting in impairments of $3.1 million and $11.1 million for the years ended December 31,

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Notes to Consolidated Financial Statements - (Continued)

2014 and 2013, respectively. The remaining net book value of these assets is included in other current assets in the accompanying consolidated balance sheet at December 31, 2014.

Gas Treating Plants and Other Midstream Assets. During 2015, 2014 and 2013, the Company evaluated certain midstream pipe inventory, natural gas compressors, gas treating plants and a CO₂ compressor station for impairment when it was determined that their future use was limited. As a result of these evaluations, the Company recorded impairments of $7.1 million, $0.6 million and $12.2 million during the years ended December 31, 2015, 2014 and 2013, respectively, on these assets to reduce their carrying value to fair value.

Other Property, Plant and Equipment. In the fourth quarter of 2015, the Company signed an agreement to sell one of its properties located in downtown Oklahoma City, Oklahoma. Because the net book value of the property exceeded the agreed upon sales price, the Company adjusted the carrying value of the property to the agreed upon sales price, resulting in an impairment of $15.4 million for the year ended December 31, 2015. Additionally the company evaluated certain gathering and compression equipment for impairment when it was determined their future use was limited. As a result of these evaluations, the Company recorded an impairment of $0.7 million for the year ended December 31, 2015.

In the second quarter of 2013, the Company committed to a plan to sell a corporate asset. The net book value of the corporate asset was adjusted to fair value, resulting in an impairment of $2.9 million during the year ended December 31, 2013. The corporate asset was sold in the fourth quarter of 2013.

9. Other Assets

Other assets consist of the following (in thousands):

	December 31,
	2015		2014
Debt issuance costs, net of amortization	$	72,259	$	56,445
Deferred tax asset(1)	—		95,843
Investments	10,106		11,106
Other	—		1,853
Total other assets	$	82,365	$	165,247

____________________

(1) The deferred tax asset at December 31, 2015, upon which there is a full valuation allowance, was netted against the deferred tax liability for presentation purposes as a result of the Company’s adoption of ASU 2015-17 in the fourth quarter of 2015. See Note 1.

10. Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):

	December 31,
	2015		2014
Accounts payable and other accrued expenses	$	231,697	$	392,500
Accrued interest	73,320		79,704
Production payable	55,260		120,573
Payroll and benefits	42,728		44,496
Convertible perpetual preferred stock dividends	21,572		11,072
Drilling advances	2,295		33,195
Related party	1,545		1,852
Total accounts payable and accrued expenses	$	428,417	$	683,392

11. 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

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

recognized construction contract revenue and costs equal to the revised contract price of $23.3 million, which are included in the accompanying consolidated statement of operations for the year ended December 31, 2013.

12. Long-Term Debt

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

	December 31,
	2015		2014
Senior credit facility	$	—	$	—
8.75% Senior Secured Notes due 2020, including mandatory prepayment feature liabilities of $2,941, and net of $29,842 discount	1,301,098		—
Senior Unsecured Notes
8.75% Senior Notes due 2020, net of $3,269 and $4,598 discount, respectively	392,666		445,402
7.5% Senior Notes due 2021, including a premium of $1,944 and $3,486, respectively	759,711		1,178,486
8.125% Senior Notes due 2022	527,737		750,000
7.5% Senior Notes due 2023, net of $1,989 and $3,452 discount, respectively	541,572		821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount	82,294		—
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount	26,428		—
Total debt	3,631,506		3,195,436
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,631,506	$	3,195,436

See Note 22 for discussion of events occurring related to long-term debt subsequent to December 31, 2015.

Senior Credit Facility

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

The senior credit facility was amended and restated on June 10, 2015 (the “June Amendment”). In connection with the June Amendment, the then-existing financial covenants were replaced. As of then and as of December 31, 2015, the senior credit facility contains financial covenants, including maintenance of agreed upon levels for the (a) ratio of total secured debt under the senior credit facility to EBITDA, which may not exceed 2.00:1.00 at each quarter end and (b) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. For the purpose of the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s commodity derivative contracts are disregarded. The senior credit facility matures on the earlier of March 2, 2020 and 91 days prior to the earliest date of any maturity under or mandatory offer to repurchase the Company’s currently outstanding senior notes.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Prior and subsequent to the June Amendment, the senior credit facility also contains various covenants that limit the ability of the Company and certain of its subsidiaries to: grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. On August 13, 2015, the senior credit facility was amended to allow the Company to redeem or purchase outstanding Senior Unsecured Notes for up to $200.0 million in cash subject to certain limitations and on October 16, 2015, concurrent with the October borrowing base redetermination, the senior credit facility was further amended to increase the amount of Senior Unsecured Notes the Company may redeem or purchase for cash to $275.0 million from $200.0 million. 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 year ended December 31, 2015, the Company was in compliance with all applicable financial covenants under the senior credit facility.

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

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

Borrowings and letter of credit obligations under the senior credit facility may not exceed the lower of the committed amount, which is currently $1.0 billion, or the borrowing base, which is $500.0 million and is subject to periodic redeterminations. Prior to the June Amendment, the borrowing base was $900.0 million. This reduction in borrowing base resulted in the write off of approximately $4.9 million of capitalized debt issuance costs. The borrowing base remained unchanged as a result of the October 2015 redetermination. The next scheduled borrowing base redetermination is expected to take place in April 2016; however, as discussed in Note 22, a special redetermination of the borrowing base was made in March 2016. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base.

The amended senior credit agreement permits the Company and certain of its subsidiaries to incur additional indebtedness in an aggregate principal amount not to exceed $1.75 billion, which may be secured solely by collateral securing the senior credit facility on a junior lien basis. Any junior lien debt shall be subject to the terms and conditions set forth in an intercreditor agreement and shall mature no earlier than January 21, 2020. The borrowing base under the senior credit facility will be reduced by $0.25 for every $1.00 of junior debt incurred above $1.50 billion.

The Company had no amounts outstanding under the senior credit facility at December 31, 2015 and $11.0 million in outstanding letters of credit, which reduce availability under the senior credit facility on a dollar-for-dollar basis. Additionally, at December 31, 2015, the Company had incurred $1.3 billion in junior lien debt subject to an intercreditor agreement as a result of the issuance of Senior Secured Notes in June 2015 and the PGC Senior Secured Notes in October 2015 as described further below.

Senior Secured Notes

Concurrent with the amendment and restatement of the Company’s senior credit facility discussed above, in June 2015 the Company issued $1.25 billion of 8.75% Senior Secured Notes due 2020. Net proceeds from the issuance were approximately $1.21 billion after deducting offering expenses, a portion of which was used to repay amounts outstanding at that time under the Company’s senior credit facility. The Senior Secured Notes were issued to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S of the Securities Act.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Additionally, the Company issued the PGC Senior Secured Notes in conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015. Because the PGC Senior Secured Notes were issued as partial consideration for the acquisition and termination, these notes were recorded at fair value of approximately $50.3 million ($78.0 million par value, including mandatory prepayment feature liabilities of $2.8 million, net of $30.5 million discount) upon their issuance. Fair value at issuance was determined based upon the then-current market value of the Senior Secured Notes. The PGC Senior Secured Notes were issued at a discount that is being amortized to interest expense over the term of the Senior Secured Notes.

The Company’s Senior Secured Notes bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due upon maturity. The Senior Secured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on a second-priority secured basis by certain of the Company’s wholly owned subsidiaries.

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

Debt issuance costs of $39.2 million incurred in connection with the offering of the Senior Secured Notes outstanding at December 31, 2015 are included in other assets in the accompanying unaudited condensed consolidated balance sheet and are being amortized to interest expense over the term of Senior Secured Notes.

Maturity Date and Mandatory Prepayment Feature. Pursuant to the indenture, the Senior Secured Notes will mature on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019. See further discussion of the mandatory prepayment feature, which with respect to the PGC Senior Secured Notes is an embedded derivative that has been accounted for separately from these notes, at Note 5 and Note 13.

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

Senior Unsecured Notes

The Company’s Senior Unsecured Notes bear interest at a fixed rate per annum, payable semi-annually, with the principal due upon maturity. Certain of the Senior Unsecured Notes were issued at a discount or a premium. The discount or premium is amortized to interest expense over the term of the respective series of Senior Unsecured Notes. The Senior Unsecured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 24 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $48.9 million incurred in connection with the offerings and subsequent registered exchange offers of the Senior Unsecured Notes outstanding, including the impact of write offs in conjunction with the repurchases and exchanges discussed below, are included in other assets in the accompanying consolidated balance sheet at December 31, 2015 and are being amortized to interest expense over the term of the respective series of Senior Unsecured Notes.

Indentures. Each of the indentures governing the Company’s Senior Unsecured Notes contains covenants that restrict the Company’s ability to take a variety of actions, including limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and during the year ended December 31, 2015, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Notes.

2015 Activity

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Notes to Consolidated Financial Statements - (Continued)

Redemption of Senior Unsecured Notes. During the second quarter of 2015, the Company issued to a holder of its 7.5% Senior Notes due 2021 and 8.125% Senior Notes due 2022, approximately 28.0 million shares of the Company’s common stock in exchange for an aggregate $50.0 million principal amount of the notes ($29.0 million of 7.5% Senior Notes due 2021 and $21.0 million of 8.125% Senior Notes due 2022) and as payment for the interest accrued thereon since the last interest payment date. The exchange resulted in a gain on extinguishment of $17.9 million, which is included in other income on the accompanying consolidated statement of operations for the year ended December 31, 2015.

Repurchase and Exchange of Senior Unsecured Notes. In August 2015, the Company repurchased $250.0 million of its Senior Unsecured Notes comprised of (i) $29.3 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $111.6 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $26.1 million aggregate principal amount of its 8.125% Senior Notes due 2022 and (iv) $83.0 million aggregate principal amount of its 7.5% Senior Notes due 2023, for approximately $94.5 million cash. The repurchase resulted in a gain on extinguishment of $152.0 million, including the write off of $3.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for the year ended December 31, 2015. In conjunction with the repurchase, the Company also exchanged $275.0 million of its Senior Unsecured Notes for newly-issued Convertible Senior Unsecured Notes, as discussed further below.

In October 2015, the Company repurchased $100.0 million of its Senior Unsecured Notes comprised of (i) $2.2 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $46.6 million aggregate principal amount of its 7.5% Senior Notes due 2021, and (iii) $51.2 million aggregate principal amount of its 7.5% Senior Notes due 2023, for approximately $30.0 million in cash. The repurchase resulted in a gain on extinguishment of $68.7 million, including the write off of $1.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for the year ended December 31, 2015. In conjunction with the repurchase, the Company also exchanged approximately $300.0 million of its Senior Unsecured Notes for newly-issued Convertible Senior Unsecured Notes, as discussed further below.

2013 Activity

In March 2013, the Company redeemed $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 consolidated statement of operations for the year ended December 31, 2013.

Convertible Senior Unsecured Notes

In conjunction with the repurchase of Senior Unsecured Notes in August 2015, the Company also exchanged $275.0 million of its Senior Unsecured Notes, comprised of (i) $15.9 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $40.7 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $101.8 million aggregate principal amounts of its 8.125% Senior Notes due 2022 and (iv) $116.6 million aggregate principal amount of its 7.5% Senior Notes due 2023, for (i) $158.4 million aggregate principal amount of newly-issued 8.125% Convertible Senior Notes due 2022 and (ii) $116.6 million aggregate principal amount of newly-issued 7.5% Convertible Senior Notes due 2023. The exchange resulted in a gain on extinguishment of $189.0 million, including the write off of $4.0 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations year ended December 31, 2015.

In conjunction with the repurchase of Senior Unsecured Notes in October 2015, the Company exchanged $300.0 million of its Senior Unsecured Notes, comprised of (i) $6.6 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $189.3 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $73.5 million aggregate principal amounts of its 8.125% Senior Notes due 2022 and (iv) $30.6 million aggregate principal amount of its 7.5% Senior Notes due 2023, for (i) $269.4 million aggregate principal amount of newly-issued 8.125% Convertible Senior Notes due 2022 and (ii) $30.6 million aggregate principal amount of newly-issued 7.5% Convertible Senior Notes due 2023. The exchange resulted in a gain on extinguishment of $207.4 million, including the write off of $4.0 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations year ended December 31, 2015.

The Convertible Senior Unsecured Notes are guaranteed by the same guarantors that guarantee the Senior Unsecured Notes and are subject to covenants and bear payment terms substantially identical to those of the corresponding series of Senior Unsecured Notes of similar tenor, other than the conversion features, described further below, and the extension of the final maturity by one day. The transactions were determined to be an extinguishment of each of the Senior Unsecured Notes exchanged. As such, the newly-issued Convertible Senior Unsecured Notes were recorded at fair value on the date of issuance, which resulted in a discount that is being amortized to interest expense over the term of the respective series of Convertible Senior Unsecured Notes.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Debt issuance costs of $6.3 million incurred in connection with the issuance of the Convertible Senior Unsecured Notes, including the impact of write offs in conjunction with the conversions discussed below, are included in other assets in the accompanying consolidated balance sheet at December 31, 2015 and are being amortized to interest expense over the term of the respective series of Convertible Senior Unsecured Notes.

Conversion Features. The Convertible Senior Unsecured Notes are convertible, at the option of the holders, into shares of common stock at any time prior to (i) the fifth business day following the date of a mandatory conversion notice, discussed further below, (ii) with respect to Convertible Senior Unsecured Notes called for redemption, the business day immediately preceding the redemption date or (iii) the business day immediately preceding the maturity date. The conversion rate isapproximately 363.6 shares of common stock per $1,000 principal amount of the Convertible Senior Unsecured Notes, subject to customary adjustments. With respect to any conversions prior to the first anniversary of the issuance of the Convertible Senior Unsecured notes, in addition to the shares deliverable upon conversion, holders are entitled to receive an early conversion payment equal to the amount of 18 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. With respect to any conversion subsequent to the first anniversary of the issuance of the Convertible Senior Unsecured Notes, but on or prior to the second anniversary of the issuance of such Convertible Senior Unsecured Notes, holders are entitled to receive an early conversion payment equal to the amount of 12 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. The dilutive effect, if any, of the Convertible Senior Unsecured Notes on the Company’s earnings per share is determined using the if-converted method. See further discussion at Note 20.

See further discussion of the holders’ conversion features, which are embedded derivatives that have been accounted for separately from the Convertible Senior Unsecured Notes, at Note 5 and Note 13.

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

Conversions to Common Stock. During the year ended December 31, 2015, holders of $186.6 million aggregate principal amount ($54.4 million net of discount and including holders’ conversion feature) of 8.125% Convertible Senior Notes due 2022 and $68.7 million aggregate principal amount ($19.3 million net of discount and holders’ conversion feature) of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 92.8 million shares of Company common stock and aggregate cash payments of $30.5 million for accrued interest and early conversion payments. The conversions resulted in a gain on extinguishment of debt totaling $6.1 million, including the write off of $5.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for year ended December 31, 2015.

Maturities of Long-Term Debt

As of December 31, 2015, $1.7 billion of long-term debt will mature in 2020, with the remainder of long-term debt maturing thereafter; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

13. 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.

Commodity Derivatives

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts, which allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Cash settlements and valuation gains and losses on commodity derivative contracts are included in (gain) loss on derivative contracts in the consolidated statements of operations. Commodity derivative contracts are settled on a monthly or quarterly basis. Derivative assets and liabilities arising from the Company’s commodity derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheets. At December 31, 2015, 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.
Basis swaps	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for oil or natural gas from a specified delivery point.
Collars	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 plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

The Company recorded (gain) loss on commodity derivative contracts of $(73.1) million, $(334.0) million and $47.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(327.7) million, $32.3 million and $(0.8) million, respectively. Included in these net cash (receipts) payments are $69.6 million and $29.6 million of cash payments related to settlements of commodity derivative contracts with contractual maturities after the year in which they were settled primarily as a result of the sale of the Gulf Properties in February 2014 and the Permian Properties in February 2013, respectively.

Derivatives Agreements with Royalty Trusts. During the years ended December 31, 2015, 2014 and 2013, the Company was party to derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts entered into by the Company with third parties. The derivatives agreements with the Mississippian Trust I and the Mississippian Trust II contained commodity derivative contracts that covered volumes of oil and natural gas production through December 31, 2015, and the derivatives agreement with the Permian Trust contained commodity derivative contracts that covered volumes of oil production through March 31, 2015. In accordance with the terms of the respective derivatives agreements, the Company novated certain of the commodity derivative contracts underlying the derivatives agreements to each of the Permian Trust and the Mississippian Trust II. As a party to these contracts, the Permian Trust and Mississippian Trust II received payment directly from the counterparty and paid any amounts owed directly to the counterparty during the terms of these novated contracts. 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. The derivatives agreements expired upon expiration of the associated underlying derivative contracts and were no longer in effect as of December 31, 2015. All activity related to the contracts underlying the derivatives agreements with the Royalty Trusts have been included in the Company’s consolidated derivative disclosures.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis in the consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of December 31, 2015, the counterparties to the Company’s open commodity derivative contracts consisted of eight financial institutions, three of which are also lenders under the Company’s senior credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as certain of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the commodity derivative contracts novated by the Company, the Permian Trust and the Mississippian Trust II gave the counterparties to such contracts a lien on their respective royalty interests. As of December 31, 2015, the terms of all such novated contracts had expired. The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the senior credit facility (in thousands):

December 31, 2015

	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Liabilities
Derivative contracts - current	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—

December 31,2014

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

F-36

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

At December 31, 2015, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2016 - December 2016	1,464	$	88.36

Natural Gas Basis Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way

	Notional (MBbls)	Sold Put		Purchased Put		Sold Call
January 2016 - December 2016	2,556	$	83.14	$	90.00	$	100.85

Long-Term Debt - Embedded Derivatives

Long-Term Debt Holder Conversion Feature. As discussed further in Note 5 and Note 12, the Convertible Senior Unsecured Notes contain a conversion feature that is exercisable at the holders’ option. This conversion feature has been identified as an embedded derivative as the feature (i) possesses economic characteristics that are not clearly and closely related to the economic characteristics of the host contract, the Convertible Senior Unsecured Notes, and (ii) separate, stand-alone instruments with the same terms would qualify as derivative instruments. As such, the holders’ conversion feature has been bifurcated and accounted for separately from the Convertible Senior Unsecured Notes. The holders’ conversion feature is recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statement of operations for the year ended December 31, 2015.

Mandatory Prepayment Feature - PGC Senior Secured Notes. As discussed further in Note 5 and Note 12, the Senior Secured Notes contain a mandatory prepayment feature that is triggered if the outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million on October 15, 2019. With respect to the PGC Senior Secured Notes, which were issued at a substantial discount, this mandatory prepayment feature has been identified as an embedded derivative as the feature (i) possesses economic characteristics that are not clearly and closely related to the economic characteristics of the host contract, the PGC Senior Secured Notes, and (ii) separate, stand-alone instruments with the same terms would qualify as derivative instruments. As such, the mandatory prepayment feature contained in the PGC Senior Secured Notes has been bifurcated and accounted for separately from those notes. The mandatory prepayment feature contained in the PGC Senior Secured notes is recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statement of operations for the year ended December 31, 2015.

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 its outstanding 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 swaps of $0.01 million for the year ended December 31, 2013, which is included in interest expense in the accompanying consolidated statement of operations. Included in the loss for the year ended December 31, 2013 are cash payments upon contract settlement of $2.4 million.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Fair Value of Derivatives

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

		December 31,
Type of Contract	Balance Sheet Classification	2015			2014
Derivative assets
Oil price swaps	Derivative contracts—current	$	68,224		$	204,072
Natural gas price swaps	Derivative contracts—current	—			29,648
Natural gas basis swaps	Derivative contracts—current	—			350
Oil collars—three way	Derivative contracts—current	17,300			56,289
Natural gas collars	Derivative contracts—current	—			1,055
Oil price swaps	Derivative contracts—noncurrent	—			36,288
Oil collars—three way	Derivative contracts—noncurrent	—			10,715
Derivative liabilities
Natural gas basis swaps	Derivative contracts—current	(1,748		)	—
Long-term debt holder conversion feature	Long-term debt	(29,355		)	—
Mandatory prepayment feature - PGC Senior Secured Notes	Long-term debt	(2,941		)	—
Total net derivative contracts		$	51,480		$	338,417

See Note 5 for additional discussion of the fair value measurement of the Company’s derivative contracts and Note 12 for discussion of the long-term debt holder conversion and mandatory prepayment features.

14. Asset Retirement Obligations

The following table presents the balance and activity of the asset retirement obligations for the years ended December 31, 2015, 2014 and 2013 (in thousands).

	2015			2014			2013
Beginning balance	$	54,402		$	424,117		$	498,410
Liability incurred upon acquiring and drilling wells	1,662			4,968			5,078
Revisions in estimated cash flows(1)	44,060			(5,848		)	(3,077		)
Liability settled or disposed in current period(2)	(1,023		)	(377,927		)	(113,071		)
Accretion	4,477			9,092			36,777
Ending balance	103,578			54,402			424,117
Less: current portion	8,399			—			87,063
Asset retirement obligations, net of current	$	95,179		$	54,402		$	337,054

____________________

(1) Revisions for the year ended December 31, 2015 relate primarily to changes in estimated well lives.

(2) Liability settled or disposed for the year ended December 31, 2014, includes $366.0 million associated with the Gulf Properties sold in February 2014, as discussed in Note 3.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

15. Commitments and Contingencies

Operating Leases. The Company has obligations under noncancelable operating leases, primarily for office space and equipment used in drilling and services activities. Total rental expense under operating leases for the years ended December 31, 2015, 2014 and 2013 was approximately $1.0 million, $1.7 million and $3.6 million, respectively.

Future minimum payments under noncancelable operating leases (with initial lease terms exceeding one year) as of December 31, 2015 were as follows (in thousands):

Years ending December 31
2016	$	584
2017	555
2018	485
2019	72
2020	—
Thereafter	—
	$	1,696

Rig Commitments. The Company has contracts with third-party drilling rig operators for the use of their rigs at specified day or footage rates. These commitments are not recorded in the consolidated balance sheets. The minimum future commitment for 2016 was $2.5 million as of December 31, 2015, with no such commitments subsequent to 2016.

Oil and Natural Gas Transportation and Throughput Agreements. The Company has subscribed firm gas transportation service under a transportation service agreement on the Midcontinent Express Pipeline, the term of which continues until July 2019. This commitment is not recorded in the consolidated balance sheets. Under the terms of the agreement, the Company is obligated to pay a demand charge and in exchange, obtains the right to flow natural gas production through this pipeline to more competitive marketing areas. The Company also has oil and natural gas throughput agreements in place, which require fixed fees based on minimum volume requirements for the right to flow oil and natural gas through certain pipelines. The amounts of the required payments related to the transportation and throughput agreements as of December 31, 2015 were as follows (in thousands):

Years ending December 31
2016	$	14,082
2017	13,869
2018	14,163
2019	9,282
2020	1,584
Thereafter	11,088
	$	64,068

Treating Agreement. At December 31, 2015, the Company was party to a 30-year treating agreement with Occidental Petroleum Corporation (“Occidental”) for the removal of CO₂ from natural gas volumes delivered by the Company. Under the agreement, the Company was required to deliver a total of approximately 3,200 Bcf of CO₂ during the agreement period. The Company was obligated to pay Occidental $0.25 per Mcf to the extent minimum annual CO₂ volume requirements were not met. Through December 31, 2015, the Company had delivered to Occidental 73.1 Bcf of CO_2, which is 439.6 Bcf less than the cumulative minimum annual CO₂ volume requirements for the same period and had accrued associated annual shortfall penalties of approximately $109.9 million. As discussed in Note 22, the Company was released from all past, current and future obligations related to this agreement in January 2016.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which depend on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company enters into commodity derivative arrangements from time to time, depending upon management’s view of opportunities under the then-prevailing current market conditions, in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 13 for the Company’s open oil

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

and natural gas commodity derivative contracts.

Production targets contained in certain gathering and treating agreements require the Company to incur capital expenditures or make associated shortfall payments, as discussed above. The Company depends on cash flows from operating activities and, as necessary, borrowings under its senior credit facility to fund its capital expenditures. Based on current cash balances, cash flows from operating activities and net borrowings under the senior credit facility in 2016, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2016; however, if current depressed oil or natural gas prices persist for a prolonged period or further decline, they would have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced, which would adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility. See Note 12 for discussion of the financial covenants in the senior credit facility and Note 22 for discussion of events occurring related to the senior credit facility subsequent to December 31, 2015.

On January 7, 2016, the Company’s stock was delisted from trading on the New York Stock Exchange as a result of having traded below certain required thresholds. Such delisting could impact the Company’s ability to generate funds from equity financing.

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

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

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

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

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

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

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

F-40

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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

On September 26, 2014, the Board 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.

On October 7, 2015, the derivative plaintiffs in the Federal Shareholder Derivative Litigation, the SLC, and the individual defendants in the Federal Shareholder Derivative Litigation (Tom Ward, Jim Brewer, Everett Dobson, William Gilliland, Daniel Jordan, Roy Oliver Jr., and Jeffrey Serota), executed a Stipulation of Settlement, which would result in a partial settlement of the Federal Shareholder Derivative Litigation by settling all claims against the individual defendants, subject to certain terms and conditions, including the approval of the court. Under the terms of the proposed partial settlement, the Company would implement or agree to maintain certain corporate governance reforms, and the insurers for the individual defendants would pay $38.0 million to an escrow fund, which would be used to pay certain expenses arising from pending securities litigation and, to the extent funds remain after paying such expenses, would be paid to the Company without any further restrictions on the Company’s use of such funds. The proposed partial settlement expressly provides, among other terms, that the settling defendants deny all allegations of wrongdoing and are entering into the settlement solely to avoid the costs, disruption, uncertainty, and risk of further litigation.

On October 9, 2015, the court issued an Order granting preliminary approval of the Stipulation of Settlement and, after notice and a hearing on December 18, 2015, the court issued a Final Judgment and Order on December 22, 2015, granting final approval of the Stipulation of Settlement. The partial settlement did not settle any of the derivative plaintiffs’ claims against non-settling defendants WCT Resources, L.L.C., 192 Investments, L.L.C., and TLW Land & Cattle, L.P in the Federal Shareholder

F-41

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Derivative Litigation. On January 12, 2016, a shareholder who objected to the Stipulation of Settlement filed a notice of appeal of the court’s Final Judgment and Order approving the Stipulation of Settlement.

On November 30, 2015, the court stayed the Hefner action until further order of the court. An estimate of reasonably possible losses associated with the Hefner action cannot be made at this time. The Company has not established any reserves relating to this action.

On December 5, 2012, James Glitz and Rodger A. Thornberry, on behalf of themselves and all other similarly situated stockholders, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain current and former executive officers of the Company. On January 4, 2013, Louis Carbone, on behalf of himself and all other similarly situated stockholders, filed a substantially similar putative class action complaint in the same court and against the same defendants. On March 6, 2013, the court consolidated these two actions under the caption “In re SandRidge Energy, Inc. Securities Litigation” (the “Securities Litigation”) and appointed a lead plaintiff and lead counsel. On July 23, 2013, plaintiffs filed a consolidated amended complaint, which asserts a variety of federal securities claims against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class of (a) purchasers of SandRidge common stock during the period from February 24, 2011 to November 8, 2012, (b) purchasers of common units of the Mississippian Trust I in or traceable to its initial public offering on or about April 12, 2011, and (c) purchasers of common units of the Mississippian Trust II (together with the Mississippian Trust I, the “Mississippian Trusts”) in or traceable to its initial public offering on or about April 23, 2012. The claims are based on allegations that the Company, certain of its current and former officers and directors, and the Mississippian Trusts, among other defendants, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and natural gas reserves, the Company's capital expenditures, and certain transactions entered into by companies allegedly affiliated with the Company's former CEO Tom Ward.

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

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

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

On July 15, 2013, James Hart and 15 other named plaintiffs filed an Amended Complaint in the United States District Court for the District of Kansas in an action undertaken individually and on behalf of others similarly situated against SandRidge Energy, Inc., SandRidge Operating Company, SandRidge 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 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.

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Notes to Consolidated Financial Statements - (Continued)

On May 27, 2015, the parties reached an agreement in principle to settle this lawsuit. Pursuant to such agreement, the Company will establish a settlement fund from which to pay participating plaintiffs’ claims as well as plaintiffs’ attorneys’ fees. The proposed settlement agreement is subject to final negotiations between the parties and court approval. During the year ended December 31, 2015, the Company established a $5.1 million reserve for this lawsuit.

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

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

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

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

On September 14, 2015, Richard A. McWilliams, individually and on behalf of all others similarly situated, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class comprised of all persons, except the named defendants and their immediate family members, who were participants in, or beneficiaries of, the Plan at any time between August 2, 2012, and the present, and whose Plan accounts included investments in SandRidge common stock. The plaintiff purports to bring the action both derivatively on the Plan’s behalf pursuant to ERISA §§ 409 and 502, and as a class action pursuant

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

to Rule 23 of the Federal Rules of Civil Procedure. The plaintiff’s claims are based on allegations that the defendants breached their fiduciary duties owed to the Plan and to the Plan participants by allowing the investment of the Plan’s assets in SandRidge common stock when it was otherwise allegedly imprudent to do so based on the financial condition of the Company and the fact the Company’s common stock was artificially inflated because, among other things, the Company materially overstated the amount of oil being produced and the ratio of oil to natural gas in one of its core holdings. On September 24, 2015, the Court consolidated this lawsuit with the Gernandt action.

On November 24, 2015, the plaintiffs filed a Consolidated Class Action Complaint in the consolidated Gernandt action. The Company intends to defend this consolidated lawsuit vigorously. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

On November 18, 2015, Mickey Peck, on behalf of himself and others similarly situated, filed a First Amended Collective Action Complaint in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc., and SandRidge Operating Company for violations of the Fair Labor Standards Act. Plaintiff alleges that the Company improperly classified certain of its consultants as independent contractors rather than as employees and, therefore, improperly paid such consultants a day rate without paying any overtime compensation. On January 14, 2016, the Court entered an Order conditionally certifying the class and providing for notice. 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 January 12, 2016, Lisa Griggs and April Marler, on behalf of themselves and all other similarly situated, filed a putative class action petition in the District Court of Logan County, Oklahoma, against SandRidge Exploration and Production, LLC, and certain other oil and gas exploration companies. In their petition, plaintiffs assert various tort claims based upon purported damage and loss resulting from earthquakes allegedly caused by the defendants’ operations of wastewater disposal wells. Plaintiffs seek to certify a class of “all residents of Oklahoma owning real property from 2011 through the time the Class is certified.” On February 16, 2016, the defendants filed a Notice of Removal of the lawsuit to the United States District Court for the Western District of Oklahoma. 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 February 12, 2016, Brenda Lene and Jon Darryn Lene filed a petition in the District Court of Logan County, Oklahoma, against SandRidge Exploration and Production, LLC, and certain other oil and gas exploration companies. In their petition, plaintiffs assert various tort claims based on their allegations that their home suffered damages due to earthquakes allegedly caused by the defendants’ operations of wastewater disposal wells. 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 March 3, 2016, Brian Thieme, on behalf of himself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that, commencing on or around December 27, 2007, and continuing until at least March 31, 2012, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties containing producing oil and natural gas wells located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Sections 1 and 3 of the Sherman Antitrust Act. Plaintiff seeks to certify two separate and distinct classes of members. 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 March 10, 2016, Don Beadles, in Trust for the Alva Synagogue Church, on behalf of himself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that since as early as December 2007, and continuing until at least as late as March 2012 (the “Relevant Class Period”), the defendants conspired to rig bids and otherwise depress the amounts they paid to property owners for the acquisition of oil and gas leasehold interests and producing properties located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Sections 1 and 3 of the Sherman Antitrust Act. Plaintiff seeks to certify a class of “all persons and entities that, during the Relevant Class Period, provided or sold to one of more of the Defendants (a) oil and gas leasehold interests on their property and/or (b) the producing

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

properties, in exchange for lease payments, including but not limited to lease bonuses.” 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 March 24, 2016, Janet L. Lowry, on behalf of herself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that, commencing on or around December 27, 2007, and continuing until at least March 31, 2012, the defendants conspired to rig bids and depress the price of royalty and bonus payments exchanged for purchases of oil and natural gas leasehold interests and interests in properties containing producing oil and natural gas wells located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Section 1 of the Sherman Antitrust Act. Plaintiff seeks to certify two separate and distinct classes of members. 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 February 4, 2015, the staff of the SEC Enforcement Division in Washington, D.C., notified the Company that it had commenced an informal inquiry concerning the Company’s accounting for, and disclosure of, its carbon dioxide delivery shortfall penalties under the terms of the Gas Treating and CO2 Delivery Agreement, dated June 29, 2008, between SandRidge Exploration and Production, LLC, and Oxy USA Inc.

Additionally, the Company received a letter from an attorney for a former employee at the Company (the “Former Employee”). In the letter, the attorney alleged, among other things, that the Former Employee had been terminated because he had objected to the levels of oil and gas reserves disclosed by the Company in its public filings. Over 85% of such reserves were calculated by an independent petroleum engineering firm.  The Audit Committee of the Company’s Board of Directors has retained an independent law firm to review the Former Employee’s allegations and the circumstances of the Former Employee’s termination.  In addition, the Company reported the Former Employee’s allegations to the SEC staff, which thereafter issued two subpoenas to the Company relating to the Former Employee’s allegations.  Counsel for the Audit Committee is responding to both of these subpoenas.

During the course of the above inquiries, the SEC issued a subpoena to the Company seeking documents relating to employment-related agreements between the Company and certain employees. The Company is cooperating with this inquiry and, after discussion with the staff, the Company sent corrective letters to certain current and former employees who had entered into agreements containing language that may have been inconsistent with SEC rules prohibiting a company from impeding an individual from communicating directly with the SEC about possible securities law violations. The Company also updated its Code of Conduct and other relevant policies.

The Company continues to cooperate with the above inquiries and is unable to predict their outcome or the possible loss, if any, that could result from their potential resolution.

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.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

16. Equity

Preferred Stock

The following table presents information regarding the Company’s preferred stock (in thousands):

	December 31,
	2015	2014
Shares authorized, $0.001 par value	50,000	50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock	2,650	2,650
7.0% Convertible perpetual preferred stock(1)	2,770	3,000

____________________

(1) For the year ended December 31, 2015, approximately 230,500 shares were converted into approximately 3.0 million shares of the Company’s common stock.

All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions, but are now freely tradable, to the extent not owned by affiliates. In December 2014, all shares of the Company’s outstanding 6.0% convertible preferred stock converted automatically into shares of the Company’s common stock at the then-prevailing conversion rate, resulting in the issuance of approximately 18.4 million shares of common stock.

Each outstanding share of convertible perpetual preferred stock is convertible at the holder’s option at any time into shares of the Company’s common stock at the specified conversion rate, subject to customary adjustments in certain circumstances. Each holder is entitled to an annual dividend payable semi-annually in cash, common stock or a combination thereof, at the Company’s election. The Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the prevailing conversion rate dependent on certain factors, including the Company’s stock trading above specified prices for a set period. The convertible perpetual preferred stock is not redeemable by the Company at any time. The following table summarizes information about each series of the Company’s convertible perpetual preferred stock outstanding at December 31, 2015:

	Convertible Perpetual Preferred Stock
	8.5%		7.0%
Liquidation preference per share	$	100.00	$	100.00
Annual dividend per share	$	8.50	$	7.00
Conversion rate per share to common stock	12.4805		12.8791

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Preferred Stock Dividends. In accordance with the terms governing the Company’s convertible perpetual preferred stock, dividends may be paid in cash or with shares of the Company’s common stock at the Company’s election. Preferred stock dividend payments and accruals for the Company’s 8.5%, 7.0% and 6.0% convertible perpetual preferred stock for the years ended December 31, 2015, 2014 and 2013 are as follows:

	December 31,
	2015		2014		2013
	(In thousands)
8.5% Convertible perpetual preferred stock
Dividends paid in cash	$	11,262	$	22,525	$	22,525
Dividends satisfied in shares of common stock(1)	$	11,262	$	—	$	—
Accrued dividends at period end	$	8,447	$	8,447	$	8,447
7.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	21,000	$	21,000
Dividends satisfied in shares of common stock(2)	$	10,500	$	—	$	—
Accrued dividends at period end	$	13,125	$	2,625	$	2,625
Dividends in arrears(3)	$	10,500	$	—	$	—
6.0% Convertible perpetual preferred stock(4)
Dividends paid in cash	$	—	$	12,000	$	12,000
Accrued dividends at period end	$	—	$	—	$	5,500

____________________

(1) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 18.6 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, ($3.58 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying condensed consolidated statement of operations.

(2) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 5.7 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, ($2.23 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying condensed consolidated statement of operations.

(3) In the third quarter of 2015, the Company announced the suspension of payment of the semi-annual dividend on shares of its 7.0% convertible perpetual preferred stock.

(4) The final dividend payment for the 6.0% convertible preferred stock was made during 2014.

Paid and unpaid dividends included in the calculation of (loss applicable) income available to the Company’s common stockholders and the Company’s basic (loss) earnings per share calculation for the years ended December 31, 2015, 2014 and 2013 are presented in the accompanying condensed consolidated statements of operations.

See Note 20 for discussion of the Company’s (loss) earnings per share calculation.

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Notes to Consolidated Financial Statements - (Continued)

Common Stock

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

The following table presents information regarding the Company’s common stock (in thousands):

	December 31,
	2015	2014
Shares authorized	1,800,000	800,000
Shares outstanding at end of period	633,471	484,819
Shares held in treasury	2,113	1,113

Redemption of Senior Unsecured Notes. During the year ended December 31, 2015, the Company issued approximately 28.0 million shares of common stock in exchange for $50.0 million in Senior Unsecured Notes. See Note 12 for additional discussion of the redemption of Senior Unsecured Notes.

Conversions of Convertible Senior Unsecured Notes. During the year ended December 31, 2015, the Company issued approximately 92.8 million shares of common stock upon the exercise of conversion options by holders of approximately $255.3 million in par value of the Convertible Senior Unsecured Notes. The Company recorded the issuance of common shares at fair value on the various dates the exchanges occurred. See Note 12 for additional discussion of the Convertible Senior Unsecured Notes transactions.

Stock Repurchase Program. In 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 the Company’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 discontinued at any time. Payment for shares repurchased under the program will be funded using the Company's working capital. During the year ended December 31, 2014, 27.4 million shares totaling $111.3 million, net of $0.5 million in broker fees and commissions, 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, the excess of the repurchase price over the par value was fully applied to additional paid-in capital.

Stockholder Rights Plan.On November 19, 2012, the Company’s Board adopted a stockholder rights plan pursuant to which the Board authorized and declared to stockholders of record on November 29, 2012 a dividend of one preferred share purchase right (the “Right”) for each outstanding share of common stock. Effective April 29, 2013, at the direction of the Board, the Company amended a stockholder rights plan, adopted in the fourth quarter of 2012, to accelerate the expiration date of the Rights to April 29, 2013, resulting in the termination of the stockholder rights plan.

See Note 17 for discussion of the Company’s share-based compensation.

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Notes to Consolidated Financial Statements - (Continued)

Treasury Stock

The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The following table shows the number of shares withheld for taxes and the associated value of those shares for the years ended December 31, 2015, 2014 and 2013. These shares were accounted for as treasury stock when withheld, and then immediately retired.

	Year Ended December 31,
	2015		2014		2013
	(In thousands)
Number of shares withheld for taxes	1,872		1,034		5,679
Value of shares withheld for taxes	$	2,428	$	6,373	$	30,126

Shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are not included as outstanding shares of common stock for accounting purposes. For corporate purposes, including for the purpose of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Stockholder Receivable

The Company is party to a settlement agreement relating to a third-party claim against its former CEO under Section 16(b) of the Securities Exchange Act of 1934, as amended. Based on the nature of the settlement as well as the former CEO’s position as an officer of the Company at the time of the settlement, the receivable related to this settlement is classified as a component of additional paid-in capital in the accompanying consolidated balance sheets. The remaining amount receivable under the agreement as of December 31, 2015 and 2014 was $1.3 million and $2.5 million, respectively.

17. Share-Based Compensation

The Company issues share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the SandRidge Energy, Inc. 2009 Incentive Plan. Total share-based compensation expense is measured using the grant date fair value for equity-classified awards and using the fair value at period end for liability-classified awards. For the years ended December 31, 2015, 2014 and 2013, the Company recognized share-based compensation expense of $21.7 million, $22.6 million and $90.2 million, respectively, net of $5.9 million, $6.0 million and $5.6 million capitalized, respectively. Amounts recognized during the year ended December 31, 2013 include approximately $48.5 million recognized in connection with the separation of certain former executives from the Company.

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SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Restricted Common Stock Awards

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

	Number of Shares		Weighted- Average Grant Date Fair Value
	(In thousands)
Unvested restricted shares outstanding at December 31, 2012	15,328		$	8.07
Granted	7,462		$	6.32
Vested	(13,395	)	$	7.85
Forfeited / Canceled	(1,752	)	$	7.33
Unvested restricted shares outstanding at December 31, 2013	7,643		$	6.92
Granted	6,367		$	6.17
Vested	(3,432	)	$	7.04
Forfeited / Canceled	(2,022	)	$	6.60
Unvested restricted shares outstanding at December 31, 2014	8,556		$	6.39
Granted	2,928		$	0.88
Vested	(5,186	)	$	4.95
Forfeited / Canceled	(672	)	$	6.38
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85

As of December 31, 2015, the Company’s unrecognized compensation cost related to unvested restricted stock awards was $18.0 million. Such cost is expected to be recognized over a weighted-average period of 1.9 years. The Company’s restricted stock awards are equity-classified awards.

Restricted Stock Units

During the year ended December 31, 2015, the Company granted restricted stock units that vest over a maximum of four years and will be settled in cash, shares of Company common stock or a combination of common stock and cash.

Restricted Stock Units - Settled in Cash or Stock. The following table presents a summary of the Company’s unvested restricted stock units which may be settled in shares of the Company’s common stock, cash or some combination of common stock and cash at the Company’s election. These restricted stock units are liability-classified awards, which vest ratably over a maximum four-year period from the date of grant and were valued at December 31, 2015 based upon the Company’s period end common stock price.

	Number of Units		Fair Value per Unit at December 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	11,095
Vested(1)	(2,200	)
Forfeited / Canceled	(767	)
Unvested units outstanding at December 31, 2015	8,128		$	0.20

____________________

(1) Restricted stock units which vested during the year ended December 31, 2015 were settled by the issuance of common stock.

As of December 31, 2015, the Company’s unrecognized compensation cost related to the unvested restricted stock units noted above was $0.9 million and is expected to be recognized over a weighted-average period of 3.2 years.

F-50

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Restricted Stock Units - Settled in Cash. The following table presents a summary of the Company’s unvested restricted stock units which will be settled in cash at the end of each vesting period for an amount based on the Company’s common stock price as of the vesting date. These restricted stock units are liability-classified awards and generally vest over a two-year period (40% at the end of the first year and 60% at the end of the second year). The restricted stock units were valued based upon the Company’s period end common stock price, discounted using a credit spread (10.6% at December 31, 2015) that was determined based upon an analysis of the historical option adjusted spread for the Company’s outstanding senior notes and the outstanding long-term debt of comparable companies.

	Number of Units		Fair Value per Unit at December 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	3,104
Vested	(979	)
Forfeited / Canceled	(122	)
Unvested units outstanding at December 31, 2015	2,003		$	0.04	-	$	0.20

As of December 31, 2015, the Company’s unrecognized compensation cost related to unvested two-year restricted stock units was $0.2 million. Such cost is expected to be recognized over a weighted-average period of 1.0 years.

Performance Units and Performance Share Units

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

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

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

	December 31,
	2015			2014
Volatility factor	120.0		%	55.6		%
Weighted-average risk-free interest rate	0.7		%	0.5		%
Weighted-average fair value per unit	$	1.08		$	13.85

F-51

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Performance unit activity for the years ended December 31, 2015, 2014 and 2013 was as follows (in thousands):

	December 31,
	2015		2014		2013(1)
Outstanding at January 1	66		31		—
Granted	—		47		31
Vested	(28	)	—		—
Forfeited /canceled	—		(12	)	—
Outstanding at December 31	38		66		31
Performance period ending December 31, 2015
Vested	—		9		12
Unvested	—		19		19
Performance period ending December 31, 2016
Vested	26		13		—
Unvested	12		25		—

____________________

(1)    The 2013 performance units fully vested on December 31, 2015, with no amounts paid.

As of December 31, 2015, the Company’s unrecognized compensation cost related to performance units granted in 2014 was insignificant and is expected to be recognized over the remaining 1.0 year term of the awards.

Performance Share Units. During the year ended December 31, 2015, the Company granted performance share units to certain members of senior management. The following table presents a summary of the fair values of the performance share units granted and the related assumptions for all outstanding performance share units at December 31, 2015.

	December 31, 2015
Volatility factor	95.3		%
Weighted-average risk-free interest rate	1.1		%
Weighted-average fair value per unit	$	0.10

Performance share unit activity for the year ended December 31, 2015 was as follows:

	Number of Performance Share Units
	(In thousands)
Outstanding at December 31, 2014	—
Granted	2,044
Forfeited /canceled	(151	)
Outstanding at December 31, 2015	1,893
Performance period ending December 31, 2017
Vested	695
Unvested	1,198

As of December 31, 2015, the Company’s unrecognized compensation cost related to performance share units granted in 2015 units was $0.1 million. Such cost is expected to be recognized over the remaining 2.0 year term of the awards.

F-52

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

18. Incentive and Deferred Compensation Plans

Annual Incentive Plan. In June 2013, the Compensation Committee of the Company’s Board approved an annual incentive plan effective June 2013 for all employees and discontinued the Company’s then existing cash bonus program with final payments under the program of approximately $10.9 million made in July 2013. For certain members of management, the annual incentive plan incorporates objective performance criteria, individual performance goals and competitive target award levels for the 2015 performance year with payout percentages ranging from 0% to 200% of specified target levels based on actual performance. As of December 31, 2015 and 2014, the Company had accrued approximately $21.6 million and $21.1 million, respectively, for the annual incentive for all employees, including an accrual for an annual incentive for specified members of management based on actual performance compared to target levels specified in the annual incentive plan. The annual incentive plan was replaced in January 2016 by the Company’s newly-implemented performance incentive plan. See Note 22.

Deferred Compensation Plans. The Company maintains a 401(k) retirement plan for its employees. Under the Plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service (“IRS”). The Company made matching contributions to the plan through cash purchases of Company stock equal to 100% on the first 10% employee deferred wages for the years ended December 31, 2015 and 2014 and 100% on the first 15% of employee deferred wages for the year ended December 31, 2013. Retirement plan expense for the years ended December 31, 2015, 2014 and 2013 was approximately $7.9 million, $8.7 million and $11.0 million, respectively.

The Company maintains a non-qualified deferred compensation plan that allows eligible highly compensated employees to elect to defer income exceeding the IRS annual limitations on qualified 401(k) retirement plans. The Company made matching contributions on non-qualified contributions up to a maximum of 10% of employee compensation for the years ended December 31, 2015 and 2014 and 15% of employee compensation for the year ended December 31, 2013. For the years ended December 31, 2015, 2014 and 2013, employer contributions of cash purchases of Company stock were approximately $2.9 million, $2.0 million and $2.7 million, respectively. Any assets placed in trust by the Company to fund future obligations of the Company’s non-qualified deferred compensation plan are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their own deferred compensation in, and the Company’s contributions to, the plan.

19. Income Taxes

The Company’s income tax provision (benefit) consisted of the following components for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2015		2014			2013
Current
Federal	$	—	$	(1,160	)	$	3,842
State	123		(1,133		)	1,842
	123		(2,293		)	5,684
Deferred
Federal	—		—			—
State	—		—			—
	—		—			—
Total provision (benefit)	123		(2,293		)	5,684
Less: income tax provision attributable to noncontrolling interest	90		283			308
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	33	$	(2,576	)	$	5,376

F-53

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax benefit is as follows for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	2015			2014			2013
Computed at federal statutory rate	$	(1,512,325	)	$	122,362		$	(178,078	)
State taxes, net of federal benefit	(19,988		)	4,145			(886		)
Non-deductible expenses	816			1,895			2,589
Non-deductible debt costs	10,228			—			—
Stock-based compensation	6,700			1,467			7,611
Net effects of consolidating the non-controlling interests’ tax provisions	218,196			(34,614		)	(13,901		)
Change in valuation allowance	1,296,405			(96,769		)	188,599
Other	1			(1,062		)	(558		)
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	33		$	(2,576	)	$	5,376

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 made 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. As of December 31, 2015, 2014 and 2013 the balance of the valuation allowance was $2.0 billion, $649.6 million, and $753.5 million, respectively. 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 December 31, 2015. Thus, the Company’s effective tax rate and tax expense for the year ended December 31, 2015 continue to be low as a result of the Company not recognizing an income tax benefit associated with its net loss from the same period.

Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):

	December 31,
	2015			2014
Deferred tax liabilities
Investments(1)	$	138,310		$	272,902
Property, plant and equipment	—			364,576
Derivative contracts	30,989			113,735
Long-term debt	10,017			—
Total deferred tax liabilities	179,316			751,213
Deferred tax assets
Property, plant and equipment	807,275			—
Allowance for doubtful accounts	18,702			19,086
Net operating loss carryforwards	1,190,799			1,265,458
Compensation and benefits	18,607			19,867
Alternative minimum tax credits and other carryforwards	44,302			43,840
Asset retirement obligations	38,314			21,946
CO2 under-delivery shortfall penalty	40,654			27,674
Other	4,305			2,934
Total deferred tax assets	2,162,958			1,400,805
Valuation allowance	(1,983,642		)	(649,592		)
Net deferred tax liability	$	—		$	—

____________________

(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. See Note 4 for further discussion of the Royalty Trusts.

F-54

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

As of December 31, 2015, the Company had approximately $9.3 million of alternative minimum tax credits available that do not expire. In addition, the Company had approximately $3.2 billion of federal net operating loss carryovers that expire during the years 2025 through 2035. Excess tax benefits of approximately $17.7 million associated with the vesting of restricted stock awards are included in the federal net operating loss carryovers, but will not be recognized as a tax benefit recorded to additional paid-in capital until realized.

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 an IRC Section 382 limitation. The limitation could result in all or a portion of the remaining $552.6 million limited net operating loss carryforwards expiring unused. The limitation did not result in a current federal tax liability at December 31, 2015.

At December 31, 2015 and 2014, the Company had a liability of approximately $0.1 million for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	December 31,
	2015		2014
Unrecognized tax benefit at January 1	$	77	$	1,382
Changes to unrecognized tax benefits related to a prior year	4		(17		)
Decreases to unrecognized tax benefits for settlements with tax authorities	—		(1,288		)
Unrecognized tax benefit at December 31	$	81	$	77

Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included insignificant amounts of accrued gross interest with respect to unrecognized tax benefits in its accompanying consolidated statements of operations during the years ended December 31, 2015, 2014 and 2013. The Company does not expect a significant change in its gross unrecognized tax benefits balance within the next 12 months.

The Company’s only taxing jurisdiction is the United States (federal and state). The Company’s tax years 2012 to present remain open for federal examination. Additionally, tax years 2005 through 2011 remain subject to examination for the purpose of determining the amount of 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.

F-55

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

20. (Loss) Earnings per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and restricted stock units, using the treasury stock method, and outstanding convertible perpetual preferred stock and convertible senior notes, using the if-converted method. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Net (Loss) Income			Weighted Average Shares	(Loss) Earnings Per Share
	(In thousands, except per share amounts)
Year Ended December 31, 2015
Basic loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Convertible preferred stock(2)	—			—
Convertible senior unsecured notes(3)	—			—
Diluted loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Year Ended December 31, 2014
Basic earnings per share	$	203,260		479,644	$	0.42
Effect of dilutive securities
Restricted stock	—			2,181
Convertible preferred stock(2)	6,500			17,918
Diluted earnings per share	$	209,760		499,743	$	0.42
Year Ended December 31, 2013
Basic loss per share	$	(609,414	)	481,148	$	(1.27	)
Effect of dilutive securities
Restricted stock(4)	—			—
Convertible preferred stock(5)	—			—
Diluted loss per share	$	(609,414	)	481,148	$	(1.27	)

____________________

(1) No incremental shares of potentially dilutive restricted stock awards or units were included for the year ended December 31, 2015 as their effect was antidilutive under the treasury stock method.

(2) Potential common shares related to the Company’s outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.2 million and 71.7 million shares for the years ended December 31, 2015 and 2014, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.

(3) Potential common shares related to the Company’s outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 48.5 million shares for the year ended December 31, 2015 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

(4) Restricted stock awards covering 0.5 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.

(5) Potential common shares related to the Company’s outstanding 8.5%, 6.0% and 7.0% convertible perpetual preferred stock covering 90.1 million shares for the year ended December 31, 2013 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

See Note 16 for discussion of the Company’s convertible perpetual preferred stock.

F-56

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

21. Related Party Transactions

The Company entered into transactions in the ordinary course of business with certain related parties. These transactions primarily consisted of sales of oil and natural gas. See Note 10 for accounts payable attributable to related party transactions. During the year ended December 31, 2013 sales to related parties were $1.6 million. This amount primarily related to sales of natural gas from the Permian Properties, which were sold in February 2013, to the Company’s partner in GRLP.

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 approximately 6.3 million shares of restricted stock awards during the third quarter of 2013. As of December 31, 2015, the remaining amount due under the terms of his employment agreement include $1.5 million to be paid in monthly installments through December 2016. This amount is included in other current liabilities in the accompanying consolidated balance sheet. See Note 16 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 years ended December 31, 2015, 2014 and 2013. For the years ended December 31, 2015 and 2014, employee termination benefits were $12.5 million and $8.9 million, respectively, primarily as a result of a reduction in workforce and executives’ separation from employment, and the sale of the Gulf Properties. For the year ended December 31, 2013, employee termination benefits, excluding amounts attributable to the Company’s former chairman and CEO, were $23.2 million, primarily as a result of other executives’ separation from employment.

Oklahoma City Thunder Agreements. Until April 2014, the Company’s former Chairman and CEO owned, and one of the Company’s directors currently owns, minority interests in a limited liability company that owns and operates the Oklahoma City Thunder basketball team. The Company was party to a sponsorship agreement, whereby it paid approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder, which terminated with the conclusion of the 2012-2013 season.

Office Lease. The Company is party to a commercial lease to rent space in a building owned by an entity that is partially owned by one of the Company’s directors. The terms provide for a lease term through December 2017 with annual rent of approximately $0.5 million. Any renovation costs paid by the Company with respect to the leased space are applied toward future rent payments. As of December 31, 2015, the Company has made renovations costing approximately $3.3 million.

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.

F-57

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

22. Subsequent Events

Royalty Trust Distributions. On January 28, 2016, the Royalty Trusts announced quarterly distributions for the three-month period ended December 31, 2015. The following distributions will be paid on February 26, 2016 to holders of record as of the close of business on February 12, 2016 (in thousands):

Royalty Trust	Total Distribution		Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I	$	8,708	$	6,367
Permian Trust	7,560		7,560
Mississippian Trust II	6,825		5,682
Total	$	23,093	$	19,609

Preferred Stock Dividends. In January 2016, the Company announced the suspension of payment of the semi-annual dividend on shares of its 8.5% convertible perpetual preferred stock.

Performance Incentive Plan. In January 2016, the Company implemented a performance incentive plan. The plan is intended to replace, on a prospective basis, the Company’s annual incentive plan and equity-based long-term incentive awards, such as restricted stock awards and restricted stock units, and provides for quarterly cash payments to participants based upon corporate performance goals with payout percentages ranging from 0% to 200%.

Personnel Reductions and Severance.The Companydiscontinued substantially all remaining drilling and oilfield services operations in January 2016 and completed a reduction in its corporate workforce in February 2016. Estimated severance costs incurred associated with these events totaled approximately $17.4 million through February 2016.

Senior Credit Facility. In January 2016, the Company borrowed the available capacity under the senior credit facility, or $488.9 million. On March 11, 2016, the administrative agent notified the Company that the lenders had elected to reduce the borrowing base to $340.0 million from $500.0 million pursuant to a special redetermination. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties.

As discussed further in Note 1, the report of the Company’s independent registered public accounting firm that accompanies these consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern, which under the terms of the senior credit facility may result in an event of default. If the Company does not obtain a waiver of this requirement or otherwise cure this event within 30 calendar days of the issuance of these consolidated financial statements, the lenders under the senior credit facility will be able to accelerate the maturity of the debt. Any acceleration of the obligations under the senior credit facility would result in a cross-default and potential acceleration of the Company’s other outstanding long-term debt.

Divestiture of WTO Properties and Release from Treating Agreement. On January 21, 2016, the Company paid $11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the WTO, including the PGC assets acquired in October 2015, to Occidental and was released from all past, current and future claims and obligations under an existing 30 years treating agreement between the companies. As of December 31, 2015, the Company had accrued approximately $109.9 million for penalties associated with shortfalls in meeting its delivery requirements under the agreement since it became effective in late 2012, including $34.9 million incurred for the year ended December 31, 2015. The Company expects to recognize a loss on the termination of the treating agreement and the cease-use of transportation agreements that support production from the Piñon field, however, is currently obtaining further information needed to evaluate the commitments extinguished and consideration conveyed in the transaction.

Production, proved reserves, revenues and direct operating expenses for the oil and natural gas properties transferred in the transaction were 1.9 MMBoe, 24.6 MMBoe, $14.6 million and $41.1 million, respectively, as of and for the year ended December 31, 2015.

F-58

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Interest Payments on Long-Term Debt. On February 16, 2016, the Company elected to defer interest payments then due with respect to its 7.5% Senior Notes due 2023 and its Senior Convertible Notes due 2023 (collectively, the “2023 Notes”). On March 15, 2016, the Company made a payment of approximately $22 million in satisfaction of its obligations under the 2023 Notes. Further, on March 16, 2016, the Company made approximately $28.4 million in interest payments then due with respect to its 7.5% Senior Notes due 2021.

Conversions of Long-Term debt to Common Stock. During the period from January 1, 2016 to March 20, 2016, holders of $200.5 million aggregate principal amount of 8.125% Convertible Senior Notes due 2022 and $31.6 million aggregate principal amount of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 84.4 million shares of Company common stock and aggregate cash payments of $33.5 million for accrued interest and early conversion payments.

23. Business Segment Information

During the years ended December 31, 2015, 2014 and 2013, the Company had three reportable business segments: exploration and production, drilling and oilfield 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 oilfield services segment is engaged in the contract drilling of oil and natural gas wells and provides various oilfield 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.

As discussed in Note 22, the Company discontinued the substantial majority of activity within its drilling and oilfield services segment in January 2016. The Company is currently evaluating the impact of this event on its segment reporting for periods within the year ending December 31, 2016.

F-59

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Management evaluates the performance of the Company’s business segments based on (loss) income 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(3)			All Other(4)			Consolidated Total
Year Ended December 31, 2015
Revenues	$	707,446		$	67,358		$	81,083		$	5,342		$	861,229
Inter-segment revenue	(12		)	(45,234		)	(47,274		)	—			(92,520		)
Total revenues	$	707,434		$	22,124		$	33,809		$	5,342		$	768,709
Loss from operations	$	(4,461,907	)	$	(59,999	)	$	(15,218	)	$	(105,554	)	$	(4,642,678	)
Interest expense, net	(42		)	—			—			(321,379		)	(321,421		)
Gain on extinguishment of debt	—			—			—			641,131			641,131
Other income, net	1,368			13			253			406			2,040
Loss before income taxes	$	(4,460,581	)	$	(59,986	)	$	(14,965	)	$	214,604		$	(4,320,928	)
Capital expenditures(5)	$	656,022		$	4,632		$	21,556		$	19,405		$	701,615
Depreciation, depletion, amortization and accretion	$	324,471		$	17,438		$	11,742		$	18,121		$	371,772
At December 31, 2015
Total assets	$	1,959,975		$	27,621		$	254,212		$	749,347		$	2,991,155
Year Ended December 31, 2014
Revenues	$	1,423,073		$	192,944		$	142,987		$	4,376		$	1,763,380
Inter-segment revenue	(173		)	(116,856		)	(87,593		)	—			(204,622		)
Total revenues	$	1,422,900		$	76,088		$	55,394		$	4,376		$	1,558,758
Income (loss) from operations	$	713,716		$	(37,564	)	$	(9,094	)	$	(76,834	)	$	590,224
Interest income (expense), net	100			—			—			(244,209		)	(244,109		)
Other (expense) income, net	(423		)	(541		)	9			4,445			3,490
Income (loss) before income taxes	$	713,393		$	(38,105	)	$	(9,085	)	$	(316,598	)	$	349,605
Capital expenditures(5)	$	1,508,100		$	18,385		$	44,606		$	37,798		$	1,608,889
Depreciation, depletion, amortization and accretion	$	443,573		$	29,105		$	10,085		$	20,260		$	503,023
At December 31, 2014
Total assets	$	6,273,802		$	115,083		$	219,691		$	650,649		$	7,259,225
Year Ended December 31, 2013
Revenues	$	1,834,480		$	187,456		$	179,989		$	3,127		$	2,205,052
Inter-segment revenue	(320		)	(120,815		)	(100,529		)	—			(221,664		)
Total revenues	$	1,834,160		$	66,641		$	79,460		$	3,127		$	1,983,388
Income (loss) from operations	$	62,509		$	(40,155	)	$	(21,567	)	$	(169,788	)	$	(169,001	)
Interest income (expense), net	1,168			—			(209		)	(271,193		)	(270,234		)
Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
Other income (expense), net	5,487			—			(3,222		)	10,180			12,445
Income (loss) before income taxes	$	69,164		$	(40,155	)	$	(24,998	)	$	(512,806	)	$	(508,795	)
Capital expenditures(5)	$	1,319,012		$	7,125		$	55,706		$	42,040		$	1,423,883
Depreciation, depletion, amortization and accretion	$	605,242		$	33,291		$	7,972		$	20,140		$	666,645

F-60

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

____________________

(1) (Loss) income from operations includes full cost ceiling limitation impairments of $4.5 billion and $164.8 million for the years ended December 31, 2015 and 2014, respectively, a loss on the sale of the Permian Properties of $398.9 million for the year ended December 31, 2013 and the Company’s (gain) loss on derivative contracts, including net cash payments upon settlement, for the years ended December 31, 2015, 2014 and 2013. See Note 13 for discussion of derivative contracts.

(2) For the years ended December 31, 2015, 2014 and 2013, (loss) income from operations includes impairments of $37.6 million, $27.4 million, and $11.1 million, respectively, on certain drilling assets.

(3) For the years ended December 31, 2015, 2014 and 2013, (loss) income from operations includes impairments of other midstream assets and the Company’s gas treating plants in west Texas of $7.1 million, $0.6 million and $3.9 million, respectively.

(4) (Loss) income from operations for the year ended December 31, 2015 includes an impairment of $15.4 million on property located in downtown Oklahoma City, Oklahoma and $0.7 million on gathering and compression equipment. See Note 7. For the year ended December 31, 2013, (loss) income from operations includes a $2.9 million impairment of a corporate asset and an $8.3 million impairment of the Company’s CO₂ compression facilities.

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

Major Customers. For the years ended December 31, 2015, 2014 and 2013, the Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):

	2015
	Sales		% of Revenue
Plains Marketing, L.P.	$	318,018	41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649	30.1	%

	2014
	Sales		% of Revenue
Plains Marketing, L.P.	$	597,117	38.3	%
Targa Pipeline Mid-Continent West OK LLC	$	333,027	21.4	%

	2013
	Sales		% of Revenue
Plains Marketing, L.P.	$	491,258	24.8	%
Shell Trading (US) Company	$	347,422	17.5	%
Targa Pipeline Mid-Continent West OK LLC	$	211,838	10.7	%

Plains Marketing, L.P., Targa Pipeline Mid-Continent West OK LLC (formerly Atlas Pipeline Mid-Continent West OK LLC) and Shell Trading (US) Company are purchasers of oil, natural gas and NGLs sold by the Company’s exploration and production segment.

F-61

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

24. Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. As of December 31, 2015, the subsidiary guarantors, which are 100% owned by the Company, have jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s outstanding Senior Unsecured Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves subsidiary guarantors; and (v) are only released under certain customary circumstances. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes.

Certain of the Company’s wholly owned subsidiaries that were sold in February 2014, as discussed in Note 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.

F-62

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Condensed Consolidating Balance Sheets

	December 31, 2015
	Parent			Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	426,917		$	847	$	7,824	$	—		$	435,588
Accounts receivable, net	—			122,606		4,781		—			127,387
Intercompany accounts receivable	1,226,994			1,305,573		30,683		(2,563,250		)	—
Derivative contracts	—			84,349		—		—			84,349
Prepaid expenses	—			6,826		7		—			6,833
Other current assets	—			19,931		—		—			19,931
Total current assets	1,653,911			1,540,132		43,295		(2,563,250		)	674,088
Property, plant and equipment, net	—			2,124,532		110,170		—			2,234,702
Investment in subsidiaries	2,749,514			8,531		—		(2,758,045		)	—
Other assets	72,259			16,008		—		(5,902		)	82,365
Total assets	$	4,475,684		$	3,689,203	$	153,465	$	(5,327,197	)	$	2,991,155
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	160,122		$	265,767	$	2,528	$	—		$	428,417
Intercompany accounts payable	1,337,688			1,192,569		32,993		(2,563,250		)	—
Derivative contracts	—			573		—		—			573
Asset retirement obligations	—			8,399		—		—			8,399
Total current liabilities	1,497,810			1,467,308		35,521		(2,563,250		)	437,389
Investment in subsidiaries	1,038,303			400,771		—		(1,439,074		)	—
Long-term debt	3,637,408			—		—		(5,902		)	3,631,506
Asset retirement obligations	—			95,179		—		—			95,179
Other long-term obligations	80			14,734		—		—			14,814
Total liabilities	6,173,601			1,977,992		35,521		(4,008,226		)	4,178,888
Stockholders’ (Deficit) Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,697,917		)	1,711,211		117,944		(1,829,155		)	(1,697,917		)
Noncontrolling interest	—			—		—		510,184			510,184
Total stockholders’ (deficit) equity	(1,697,917		)	1,711,211		117,944		(1,318,971		)	(1,187,733		)
Total liabilities and stockholders’ (deficit) equity	$	4,475,684		$	3,689,203	$	153,465	$	(5,327,197	)	$	2,991,155

F-63

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

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

____________________

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

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

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

F-64

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2015
Total revenues	$	—		$	682,778		$	85,939		$	(8	)	$	768,709
Expenses
Direct operating expenses	—			364,483			10,879			(8		)	375,354
General and administrative	213			145,796			4,157			—			150,166
Depreciation, depletion, amortization and accretion	—			339,647			32,125			—			371,772
Impairment	—			3,599,810			934,879			—			4,534,689
Gain on derivative contracts	—			(65,049		)	(8,012		)	—			(73,061		)
Loss on settlement of contract	—			50,976			—			—			50,976
Loss (gain) on sale of assets	—			2,217			(726		)	—			1,491
Total expenses	213			4,437,880			973,302			(8		)	5,411,387
Loss from operations	(213		)	(3,755,102		)	(887,363		)	—			(4,642,678		)
Equity earnings from subsidiaries	(4,017,082		)	(263,847		)	—			4,280,929			—
Interest expense, net	(321,378		)	(43		)	—			—			(321,421		)
Gain on extinguishment of debt	641,131			—			—			—			641,131
Other income, net	—			1,910			130			—			2,040
Loss before income taxes	(3,697,542		)	(4,017,082		)	(887,233		)	4,280,929			(4,320,928		)
Income tax expense	3			—			120			—			123
Net loss	(3,697,545		)	(4,017,082		)	(887,353		)	4,280,929			(4,321,051		)
Less: net loss attributable to noncontrolling interest	—			—			—			(623,506		)	(623,506		)
Net loss attributable to SandRidge Energy, Inc.	$	(3,697,545	)	$	(4,017,082	)	$	(887,353	)	$	4,904,435		$	(3,697,545	)

F-65

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2014
Total revenues	$	—		$	1,341,531		$	217,367		$	(140	)	$	1,558,758
Expenses
Direct operating expenses	—			467,175			16,854			(140		)	483,889
General and administrative	331			118,249			4,285			—			122,865
Depreciation, depletion, amortization and accretion	—			446,149			56,874			—			503,023
Impairment	—			150,125			42,643			—			192,768
Gain on derivative contracts	—			(292,733		)	(41,278		)	—			(334,011		)
Total expenses	331			888,965			79,378			(140		)	968,534
(Loss) income from operations	(331		)	452,566			137,989			—			590,224
Equity earnings from subsidiaries	495,154			38,967			—			(534,121		)	—
Interest (expense) income, net	(244,209		)	100			—			—			(244,109		)
Other income (expense), net	—			3,521			(31		)	—			3,490
Income before income taxes	250,614			495,154			137,958			(534,121		)	349,605
Income tax (benefit) expense	(2,671		)	—			378			—			(2,293		)
Net income	253,285			495,154			137,580			(534,121		)	351,898
Less: net income attributable to noncontrolling interest	—			—			—			98,613			98,613
Net income attributable to SandRidge Energy, Inc.	$	253,285		$	495,154		$	137,580		$	(632,734	)	$	253,285

F-66

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Total revenues	$	—		$	1,675,481		$	308,300		$	(393	)	$	1,983,388
Expenses
Direct operating expenses	—			654,080			29,143			(393		)	682,830
General and administrative	329			323,808			6,288			—			330,425
Depreciation, depletion, amortization and accretion	—			581,435			85,210			—			666,645
Impairment	—			15,038			11,242			—			26,280
Loss on derivative contracts	—			24,702			22,421			—			47,123
Loss on sale of assets	—			291,743			107,343			—			399,086
Total expenses	329			1,890,806			261,647			(393		)	2,152,389
(Loss) income from operations	(329		)	(215,325		)	46,653			—			(169,001		)
Equity earnings from subsidiaries	(195,118		)	3,075			—			192,043			—
Interest (expense) income, net	(271,193		)	959			—			—			(270,234		)
Loss on extinguishment of debt	(82,005		)	—			—			—			(82,005		)
Other income (expense), net	—			16,173			(3,728		)	—			12,445
(Loss) income before income taxes	(548,645		)	(195,118		)	42,925			192,043			(508,795		)
Income tax expense	5,244			—			440			—			5,684
Net (loss) income	(553,889		)	(195,118		)	42,485			192,043			(514,479		)
Less: net income attributable to noncontrolling interest	—			—			—			39,410			39,410
Net (loss) income attributable to SandRidge Energy, Inc.	$	(553,889	)	$	(195,118	)	$	42,485		$	152,633		$	(553,889	)

F-67

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2015
Net cash (used in) provided by operating activities	$	(326,674	)	$	524,313		$	124,626		$	51,272		$	373,537
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(879,201		)	—			—			(879,201		)
Acquisition of assets	—			(216,943		)	—			—			(216,943		)
Other	—			74,140			907			(18,543		)	56,504
Net cash (used in) provided by investing activities	—			(1,022,004		)	907			(18,543		)	(1,039,640		)
Cash flows from financing activities
Proceeds from borrowings	2,065,000			—			—			—			2,065,000
Repayments of borrowings	(939,466		)	—			—			—			(939,466		)
Distributions to unitholders	—			—			(158,629		)	20,324			(138,305		)
Intercompany (advances) borrowings, net	(475,618		)	497,140			(21,522		)	—			—
Other	(66,793		)	—			53,055			(53,053		)	(66,791		)
Net cash provided by (used in) financing activities	583,123			497,140			(127,096		)	(32,729		)	920,438
Net increase (decrease) in cash and cash equivalents	256,449			(551		)	(1,563		)	—			254,335
Cash and cash equivalents at beginning of year	170,468			1,398			9,387			—			181,253
Cash and cash equivalents at end of year	$	426,917		$	847		$	7,824		$	—		$	435,588

F-68

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

	Parent(1)			Guarantors(1)(2)			Non-Guarantors			Eliminations(2)			Consolidated
	(In thousands)
Year Ended December 31, 2014
Net cash (used in) provided by operating activities	$	(240,932	)	$	641,181		$	212,427		$	8,438		$	621,114
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(1,553,332		)	—			—			(1,553,332		)
Proceeds from sale of assets	—			711,728			2,747			—			714,475
Other	—			28,256			1,140			(47,780		)	(18,384		)
Net cash (used in) provided by investing activities	—			(813,348		)	3,887			(47,780		)	(857,241		)
Cash flows from financing activities
Distributions to unitholders	—			—			(234,327		)	40,520			(193,807		)
Repurchase of common stock	(111,827		)	—			—			—			(111,827		)
Intercompany (advances) borrowings, net	(215,368		)	215,373			(5		)	—			—
Other	(66,910		)	(42,821		)	19,260			(1,178		)	(91,649		)
Net cash (used in) provided by financing activities	(394,105		)	172,552			(215,072		)	39,342			(397,283		)
Net (decrease) increase in cash and cash equivalents	(635,037		)	385			1,242			—			(633,410		)
Cash and cash equivalents at beginning of year	805,505			1,013			8,145			—			814,663
Cash and cash equivalents at end of year	$	170,468		$	1,398		$	9,387		$	—		$	181,253

____________________

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

(2) Other investing activities for the Guarantor has increased to correctly exclude $193.8 million in noncontrolling interest distributions, with a corresponding decrease for Eliminations for this same line item. In addition, other financing activities for the Guarantor, has decreased to correctly exclude $193.8 million of noncontrolling interest distributions, with a corresponding increase for Eliminations for the same line item. The corrections did not result in any changes to consolidated net cash (used in) provided by investing activities or net cash used in financing activities.

F-69

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Net cash (used in) provided by operating activities	$	(239,026	)	$	852,026		$	254,723		$	907		$	868,630
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(1,496,731		)	—			—			(1,496,731		)
Proceeds from sale of assets	—			2,566,742			17,373			—			2,584,115
Other	—			89,606			3,197			(109,831		)	(17,028		)
Net cash used in investing activities	—			1,159,617			20,570			(109,831		)	1,070,356
Cash flows from financing activities
Repayments of borrowings	(1,115,500		)	—			—			—			(1,115,500		)
Premium on debt redemption	(61,997		)	—			—			—			(61,997		)
Distributions to unitholders	—			—			(299,675		)	93,205			(206,470		)
Dividends paid—preferred	(55,525		)	—			—			—			(55,525		)
Intercompany borrowings (advances) , net	2,009,146			(2,018,212		)	9,066			—			—
Other	(31,821		)	6,660			14,845			15,719			5,403
Net cash provided by (used in) financing activities	744,303			(2,011,552		)	(275,764		)	108,924			(1,434,089		)
Net increase (decrease) in cash and cash equivalents	505,277			91			(471		)	—			504,897
Cash and cash equivalents at beginning of year	300,228			922			8,616			—			309,766
Cash and cash equivalents at end of year	$	805,505		$	1,013		$	8,145		$	—		$	814,663

F-70

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

25. Supplemental Information on Oil and Natural Gas Producing Activities

The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):

	December 31,
	2015			2014			2013
Oil and natural gas properties
Proved	$	12,529,681		$	11,707,147		$	10,972,816
Unproved	363,149			290,596			531,606
Total oil and natural gas properties	12,892,830			11,997,743			11,504,422
Less accumulated depreciation, depletion and impairment	(11,149,888		)	(6,359,149		)	(5,762,969		)
Net oil and natural gas properties capitalized costs	$	1,742,942		$	5,638,594		$	5,741,453

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):

	Year Ended December 31,
	2015		2014		2013
Acquisitions of properties
Proved	$	35,376	$	73,370	$	21,130
Unproved	210,065		123,649		100,242
Exploration(1)	29,297		41,070		82,775
Development	571,562		1,288,395		1,131,269
Total cost incurred	$	846,300	$	1,526,484	$	1,335,416

____________________

(1) Includes seismic costs of $7.1 million, $10.8 million and $6.7 million for 2015, 2014 and 2013, respectively.

F-71

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Results of Operations for Oil and Natural Gas Producing Activities (Unaudited)

The Company’s results of operations from oil and natural gas producing activities for each of the years 2015, 2014 and 2013 are shown in the following table (in thousands):

	Year Ended December 31,
	2015			2014(1)			2013
Revenues	$	707,434		$	1,420,879		$	1,820,278
Expenses
Production costs	324,141			377,819			548,719
Depreciation and depletion	319,913			434,295			567,732
Accretion of asset retirement obligations	4,477			9,092			36,777
Impairment	4,473,787			164,779			—
Total expenses	5,122,318			985,985			1,153,228
(Loss) income before income taxes	(4,414,884		)	434,894			667,050
Income tax expense (benefit)(2)	126			(2,852		)	(7,471		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	(4,415,010	)	$	437,746		$	674,521

____________________

(1) Total expenses increased by $164.8 million and benefit of income taxes decreased by $1.1 million to correctly include the impact of the ceiling test impairment incurred during the year ended December 31, 2014.

(2) Reflects the Company’s effective tax rate for each period.

Oil, Natural Gas and NGL Reserve Quantities (Unaudited)

Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:

• the quality and quantity of available data and the engineering and geological interpretation of that data;

• estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

• the accuracy of mandated economic assumptions such as the future prices of oil, natural gas and NGLs; and

• the judgment of the personnel preparing the estimates.

Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

The table below represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Estimates of the substantial majority of the Company’s proved reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management

F-72

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.

Cawley, Gillespie & Associates, Inc. (“CG&A”), Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2015, 2014 and 2013. CG&A, Ryder Scott and Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. CG&A and Netherland Sewell prepared the estimates of proved reserves for a majority of the Company’s properties as of December 31, 2015. The remaining 9.9% of estimates of proved reserves was based on Company estimates.

The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

2015 Activity. During 2015, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 9.7 MMBbls, 9.3 MMBbls, and 160.9 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Acquisition of the Rockies assets, located in Jackson County, Colorado, in December 2015 added 27.6 MMBoe of reserves. These positive revisions were offset by (i) negative pricing revisions of approximately 54 MMBbls for oil, 36 MMBbls for NGLs and 687 Bcf for natural gas, due primarily to significantly lower commodity prices in 2015, and (ii) negative revisions of approximately 16 MMBbls for oil, 1 MMBbls for NGLs and 74 Bcf for natural gas primarily from well performance in the Mid-Continent.

2014 Activity. During 2014, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 37.6 MMBbls, 27.5 MMBbls, and 467.2 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Revisions of previous estimates decreased oil reserves by 18.7 MMBbls, primarily comprised of (i) approximately 9 MMBbls from Permian Basin proved undeveloped reserves, largely due to removal of drilling locations not expected to be drilled within a five year period, (ii) approximately 8 MMBbls from well performance in the Mid-Continent and (iii) approximately 2 MMBbls from acreage losses or revisions to well interest ownerships. These negative revisions were offset by positive revisions to NGL and gas reserves of 11.1 MMBbls and 167.6 Bcf, respectively, primarily from well performance in the Mid-Continent area. Acquisitions of reserves added 3.5 MMBoe.

Sales of proved reserves during 2014 totaled 55.5 MMBoe from the sale of the Gulf Properties.

2013 Activity. The Company sold its Permian Properties in February 2013. Proved reserves were 198.9 MMBoe, 55% of which were proved developed reserves, for the Permian Properties at December 31, 2012. Estimated standardized measure of discounted cash flows for the Permian Properties, determined by allocating the Company's standardized measure of discounted cash flows to the Permian Properties based on the present value of discounted cash flows attributable to the Permian Properties relative to the Company's total present value of discounted cash flows was $2.5 billion. See Note 3 for additional information regarding the sale. The Company recognized an increase of 119.2 MMBoe in total reserves primarily attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent.

F-73

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

The summary below presents changes in the Company’s estimated reserves for 2013, 2014 and 2015.

	Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2012	262,045		67,994		1,415,042
Revisions of previous estimates	(13,969	)	3,717		(53,432	)
Acquisitions of new reserves	43		13		363
Extensions and discoveries	40,570		18,686		359,918
Sales of reserves in place	(131,769	)	(29,067	)	(228,229	)
Production	(14,279	)	(2,291	)	(103,233	)
As of December 31, 2013(2)	142,641		59,052		1,390,429
Revisions of previous estimates	(18,687	)	11,103		167,589
Acquisitions of new reserves	1,009		441		12,527
Extensions and discoveries	37,603		27,500		467,185
Sales of reserves in place	(25,659	)	(2,516	)	(163,800	)
Production	(10,876	)	(3,794	)	(85,697	)
As of December 31, 2014(2)	126,031		91,786		1,788,233
Revisions of previous estimates	(70,708	)	(37,384	)	(759,106	)
Acquisitions of new reserves	22,447		2,460		15,952
Extensions and discoveries	9,741		9,257		160,865
Production	(9,600	)	(5,044	)	(92,104	)
As of December 31, 2015(2)	77,911		61,075		1,113,840
Proved developed reserves
As of December 31, 2012	136,605		33,785		896,701
As of December 31, 2013	83,893		35,807		951,609
As of December 31, 2014	79,022		56,823		1,203,447
As of December 31, 2015	48,639		51,089		964,617
Proved undeveloped reserves
As of December 31, 2012	125,440		34,209		518,341
As of December 31, 2013	58,748		23,245		438,820
As of December 31, 2014	47,009		34,963		584,786
As of December 31, 2015	29,272		9,986		149,223

____________________

(1) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

(2) Includes proved reserves attributable to noncontrolling interests at December 31, 2015, 2014 and 2013 as shown in the table below:

	December 31,
	2015	2014	2013
Oil (MBbl)	7,004	11,027	13,569
NGL (MBbl)	3,694	4,761	4,737
Natural gas (MMcf)	50,508	70,833	69,693

F-74

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas (“ASC Topic 932”). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:

• the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;

• pricing is applied based upon 12-month average market prices at December 31, 2015, 2014 and 2013 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:

	At December 31,
	2015		2014		2013
Oil (per barrel)	$	45.29	$	91.65	$	95.67
NGL (per barrel)	$	12.68	$	32.79	$	31.40
Natural gas (per Mcf)	$	1.87	$	3.61	$	3.65

• future development and production costs are determined based upon actual cost at year-end;

• the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and

• a discount factor of 10% per year is applied annually to the future net cash flows.

The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).

	At December 31,
	2015			2014			2013
Future cash inflows from production	$	6,387,944		$	21,022,320		$	19,937,484
Future production costs	(2,731,542		)	(6,499,366		)	(6,843,713		)
Future development costs(1)	(838,945		)	(1,810,201		)	(2,546,680		)
Future income tax expenses	(901		)	(3,223,740		)	(2,283,541		)
Undiscounted future net cash flows	2,816,556			9,489,013			8,263,550
10% annual discount	(1,501,994		)	(5,401,261		)	(4,245,939		)
Standardized measure of discounted future net cash flows(2)	$	1,314,562		$	4,087,752		$	4,017,611

____________________

(1) Includes abandonment costs.

(2) Includes approximately $224.6 million, $643.3 million and $781.6 million attributable to noncontrolling interests at December 31, 2015, 2014 and 2013 respectively.

F-75

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):

Present value as of December 31, 2012	$	5,840,368
Changes during the year
Revenues less production and other costs	(1,271,559		)
Net changes in prices, production and other costs	271,566
Development costs incurred	474,275
Net changes in future development costs	(207,729		)
Extensions and discoveries	1,406,102
Revisions of previous quantity estimates	(296,418		)
Accretion of discount	711,385
Net change in income taxes	477,328
Purchases of reserves in-place	1,628
Sales of reserves in-place	(3,172,187		)
Timing differences and other(1)	(217,148		)
Net change for the year	(1,822,757		)
Present value as of December 31, 2013(2)	4,017,611
Changes during the year
Revenues less production and other costs	(1,043,060		)
Net changes in prices, production and other costs	331,694
Development costs incurred	364,262
Net changes in future development costs	(341,183		)
Extensions and discoveries	1,785,963
Revisions of previous quantity estimates	(77,688		)
Accretion of discount	477,458
Net change in income taxes	(256,371		)
Purchases of reserves in-place	50,958
Sales of reserves in-place	(1,058,330		)
Timing differences and other(1)	(163,562		)
Net change for the year	70,141
Present value as of December 31, 2014(2)	4,087,752
Changes during the year
Revenues less production and other costs	(383,293		)
Net changes in prices, production and other costs	(3,813,465		)
Development costs incurred	217,596
Net changes in future development costs	273,437
Extensions and discoveries	230,055
Revisions of previous quantity estimates	(1,354,778		)
Accretion of discount	512,483
Net change in income taxes	1,426,333
Purchases of reserves in-place	18,429
Sales of reserves in-place	—
Timing differences and other(1)	100,013
Net change for the year	(2,773,190		)
Present value as of December 31, 2015(2)	$	1,314,562

____________________

(1) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2) Includes approximately $224.6 million, $643.3 million and $781.6 million attributable to noncontrolling interests at December 31, 2015, 2014, and 2013 respectively.

F-76

SandRidge Energy, Inc. and Subsidiaries

Notes to Consolidated Financial Statements - (Continued)

26. Quarterly Financial Results (Unaudited)

The Company’s operating results for each quarter of 2015 and 2014 are summarized below (in thousands, except per share data).

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2015
Total revenues	$	215,308		$	229,607		$	180,152		$	143,642
Loss from operations(1)(2)	$	(1,088,456	)	$	(1,535,083	)	$	(1,059,733	)	$	(959,406	)
Net loss(1)(2)	$	(1,151,874	)	$	(1,588,731	)	$	(796,485	)	$	(783,961	)
Loss applicable to SandRidge Energy, Inc. common stockholders(1)(2)	$	(1,045,834	)	$	(1,375,556	)	$	(649,526	)	$	(664,579	)
Loss applicable per share to SandRidge Energy, Inc. common stockholders(3)
Basic	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
Diluted	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
2014
Total revenues	$	443,056		$	374,714		$	394,107		$	346,881
(Loss) income from operations(4)(5)	$	(82,330	)	$	42,079		$	256,491		$	373,984
Net (loss) income(4)(5)	$	(142,406	)	$	(17,252	)	$	197,499		$	314,057
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(4)(5)	$	(150,217	)	$	(46,775	)	$	145,957		$	254,295
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders(3)
Basic	$	(0.31	)	$	(0.10	)	$	0.30		$	0.55
Diluted	$	(0.31	)	$	(0.10	)	$	0.27		$	0.48

____________________

(1) Includes impairment of $1.1 billion, $1.5 billion, $1.1 billion and $886.8 million for the first, second, third and fourth quarters, respectively. See Note 8 for further discussion of impairment.

(2) Includes (gain) loss on derivative contracts of $(49.8) million, $33.0 million, $(42.2) million and $(14.0) million for the first, second, third and fourth quarters, respectively.

(3) (Loss applicable) income available per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of (loss applicable) income available per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

(4) Includes a full cost ceiling limitation impairment of $164.8 million in the first quarter and impairments of drilling assets of $3.1 million and $24.3 million in the second and fourth quarters, respectively.

(5) Includes loss (gain) on derivative contracts of $42.5 million, $85.3 million, $(132.6) million and $(329.2) million for the first, second, third and fourth quarters, respectively.

F-77

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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/    JAMES D. BENNETT
		James D. Bennett,
		President and Chief Executive Officer
March 30, 2016

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Julian Bott, Philip T. Warman and Justin P. Byrne, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ JAMES D. BENNETT	President, Chief Executive Officer and Director (Principal Executive Officer)	March 30, 2016
James D. Bennett
/s/ JULIAN BOTT	Chief Financial Officer and Executive Vice President (Principal Financial Officer)	March 30, 2016
Julian Bott
/s/ LISA E. KLEIN	Vice President—Financial Reporting (Principal Accounting Officer)	March 30, 2016
Lisa E. Klein
/s/ J. MICHAEL STICE	Director	March 30, 2016
J. Michael Stice
/s/ EVERETT R. DOBSON	Director	March 30, 2016
Everett R. Dobson
/s/ JIM J. BREWER	Director	March 30, 2016
Jim J. Brewer
/s/ JEFFERY S. SEROTA	Director	March 30, 2016
Jeffery S. Serota
/s/ EDWARD W. MONEYPENNY	Director	March 30, 2016
Edward W. Moneypenny
/s/ STEPHEN C. BEASLEY	Director	March 30, 2016
Stephen C. Beasley
/s/ ALAN J. WEBER	Director	March 30, 2016
Alan J. Weber
/s/ DAN A. WESTBROOK	Director	March 30, 2016
Dan A. Westbrook

EXHIBIT INDEX

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
2.1	Equity Purchase Agreement dated as of January 6, 2014, between SandRidge Energy, Inc., SandRidge Holdings, Inc. and Fieldwood Energy LLC	8-K	001-33784	2.1	1/9/2014
3.1	Certificate of Incorporation of SandRidge Energy, Inc.	S-1	333-148956	3.1	1/30/2008
3.2	Certificate of Amendment to the Certificate of Incorporation of SandRidge Energy, Inc., dated July 16, 2010	10-Q	001-33784	3.2	8/9/2010
3.3	Certificate of Designation of 8.5% Convertible Perpetual Preferred Stock of SandRidge Energy, Inc.	8-K	001-33784	3.1	1/21/2009
3.4	Certificate of Designation of 6.0% Convertible Perpetual Preferred Stock of SandRidge Energy, Inc.	8-K	001-33784	3.1	12/22/2009
3.5	Certificate of Designation of 7.0% Convertible Perpetual Preferred Stock of SandRidge Energy, Inc.	8-K	001-33784	3.1	11/10/2010
3.6	Certificate of Designations of Series A Junior Participating Preferred Stock of SandRidge Energy, Inc.	8-K	001-33784	3.1	11/20/2012
3.7	Certificate of Elimination of Series A Junior Participating Preferred Stock of SandRidge Energy, Inc.	8-K	001-33784	3.1	4/30/2013
3.8	Amended and Restated Bylaws of SandRidge Energy, Inc.	8-K	001-33784	3.1	3/9/2009
3.9	Amendment to the March 3, 2009 Amended and Restated Bylaws of SandRidge Energy, Inc. effective November 19, 2012	8-K	001-33784	3.2	11/20/2012
4.1	Specimen Stock Certificate representing common stock of SandRidge Energy, Inc.	S-1	333-148956	4.1	1/30/2008
4.2	Indenture, dated December 16, 2009, by and among SandRidge Energy, Inc., certain subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee	8-K	001-33784	4.1	12/22/2009
4.3	Indenture, dated March 15, 2011, by and among the SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee	8-K	001-33784	4.1	3/18/2011
4.4	Indenture, dated as of April 17, 2012, among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association	8-K	001-33784	4.1	4/17/2012
4.5	Supplemental Indenture, dated April 17, 2012, among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee	8-K	001-33784	4.3	4/17/2012
4.6	Supplemental Indenture, dated June 1, 2012, among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee	10-Q	001-33784	4.3	8/6/2012
4.7	Indenture, dated as of August 20, 2012, among SandRidge Energy, Inc., certain subsidiary guarantors named therein, and Wells Fargo Bank, National Association, as trustee	8-K	001-33784	4.4	8/21/2012
4.8	Indenture, dated as of June 10, 2015, among SandRidge Energy, Inc., the guarantors named therein and U.S. Bank National Association, as Trustee (including the form of the Notes)	8-K	001-33784	4.1	6/11/2015

4.9	Indenture, dated as of August 19, 2015, among SandRidge Energy, Inc., the guarantors named therein and U.S. Bank National Association, as Trustee (including the form of the 2022 Convertible Notes).	8-K	001-33784	4.1	8/19/2015
4.10	Indenture, dated as of August 19, 2015, among SandRidge Energy, Inc., the guarantors named therein and U.S. Bank National Association, as Trustee (including the form of the 2023 Convertible Notes).	8-K	001-33784	4.2	8/19/2015
10.1†	Executive Nonqualified Excess Plan	8-K	001-33784	10.1	7/15/2008
10.2.1†	SandRidge Energy, Inc. 2009 Incentive Plan (as amended on July 1, 2013)	10-K	001-33784	10.2	2/28/2014
10.2.2†	Amendment to the SandRidge Energy, Inc. 2009 Incentive Plan	10-Q	001-33784	10.3	8/8/2013
10.2.3†	Amendment 2 to the SandRidge Energy, Inc. 2009 Incentive Plan	10-Q	001-33784	10.2.1	8/6/2015
10.2.4†	Form of Restricted Stock Certificate for SandRidge Energy, Inc. 2009 Incentive Plan	10-K	001-33784	10.2.3	2/27/2015
10.2.5†	Form of Performance Unit Certificate for SandRidge Energy, Inc. 2009 Incentive Plan	10-K	001-33784	10.2.4	2/27/2015
10.2.6†	Form of Restricted Stock Unit Certificate for SandRidge Energy, Inc. 2009 Incentive Plan	10-K	001-33784	10.2.5	2/27/2015
10.2.7†	Form of Performance Share Unit Certificate for SandRidge Energy, Inc. 2009 Incentive Plan	10-K	001-33784	10.2.6	2/27/2015
10.2.8†	Form of Restricted Stock Unit Certificate for SandRidge Energy, Inc. 2009 Incentive Plan - March 2015 Retention Grant	10-Q	001-33784	10.2.2	8/6/2015
10.2.9†	Form of Incentive Unit Certificate for SandRidge Energy, Inc. 2009 Incentive Plan - March 2015 Retention Grant	10-Q	001-33784	10.2.3	8/6/2015
10.2.10†	Form of Restricted Stock Unit Certificate for SandRidge Energy, Inc. 2009 Incentive Plan - Non-employee Director Grant	10-Q	001-33784	10.2.4	8/6/2015
10.3.1†	Employment Agreement, effective as of August 12, 2014, between SandRidge Energy, Inc. and James D. Bennett	10-K	001-33784	10.3.1	2/27/2015
10.3.2†	Employment Agreement, effective as of August 17, 2015, between SandRidge Energy, Inc. and Julian Bott.	8-K	001-33784	10.1	8/5/2015
10.3.3†	Employment Agreement, effective as of December 30, 2013, between SandRidge Energy, Inc. and Duane Grubert	10-K	001-33784	10.3.2	2/27/2015
10.3.4†	Form of Employment Agreement for Executive Vice Presidents and Senior Vice Presidents of SandRidge Energy, Inc.	10-K	001-33784	10.3.3	2/27/2015
10.3.5†	2015 Form of Employment Agreement for Executive Vice Presidents and Senior Vice Presidents of SandRidge Energy, Inc.	10-Q	001-33784	10.3.4	11/5/2015
10.3.6†	Professional Services Agreement, effective as of March 1, 2016, between SandRidge Energy, Inc. and Randall D. Cooley					*
10.4†	Form of Indemnification Agreement for directors and officers	S-1	333-148956	10.5	1/30/2008
10.5.1	Fourth Amended and Restated Credit Agreement, dated as of June 10, 2015, among SandRidge Energy, Inc., Royal Bank of Canada, as Administrative Agent, and the other lenders party thereto	8-K	001-33784	10.4	6/11/2015

10.5.2	First Amendment to Fourth Amended and Restated Credit Agreement, dated as of August 13, 2015, by and among the Company, as borrower, Royal Bank of Canada, as administrative agent, and the lenders signatory thereto.	8-K	001-33784	10.1	8/14/2015
10.5.3	Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 16, 2015, by and among the Company, as borrower, Royal Bank of Canada, as administrative agent, and the lenders signatory thereto.	8-K	001-33784	10.1	10/19/2015
10.6	Intercreditor Agreement, dated as of June 10, 2015, Royal Bank of Canada, as Priority Lien Agent, and U.S. Bank National Association, as the Second Lien Collateral Trustee	8-K	001-33784	10.1	6/11/2015
10.7	Collateral Trust Agreement, dated as of June 10, 2015, by and among SandRidge Energy, Inc., the guarantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Parity Lien Representatives from time to time party thereto and U.S. Bank National Association, as Collateral Trustee	8-K	001-33784	10.2	6/11/2015
10.8	Security Agreement, dated as of June 10, 2015, by and among SandRidge Energy, Inc., the guarantors from time to time party thereto and U.S. Bank National Association, as Collateral Trustee	8-K	001-33784	10.3	6/11/2015
21.1	Subsidiaries of SandRidge Energy, Inc.					*
23.1	Consent of PricewaterhouseCoopers LLP					*
23.2	Consent of Cawley, Gillespie & Associates					*
23.3	Consent of Netherland, Sewell & Associates, Inc.					*
23.4	Consent of Ryder Scott Company, L.P.					*
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					*
99.1	Report of Cawley, Gillespie & Associates					*
99.2	Report of Netherland, Sewell & Associates, Inc.					*
99.3	Report of Ryder Scott Company, L.P.
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					*
† Management contract or compensatory plan or arrangement

EX-10.3.6

Exhibit 10.3.6

PROFESSIONAL SERVICES AGREEMENT

THIS PROFESSIONAL SERVICES AGREEMENT (“Agreement”), dated March 10, 2016 and effective as of March 1, 2016, by and between SANDRIDGE ENERGY, INC., a Delaware corporation (“Company”), and Randy Cooley, an individual (“Contractor”).

WHEREAS, Company desires to retain the services of Contractor, and Contractor desires to provide services to Company subject to the terms and conditions of this Agreement.

NOW, THEREFORE, in consideration of the mutual promises herein contained, Company and Contractor agree as follows:

1.Services. Subject to the terms and conditions set forth in this Agreement, Company hereby retains Contractor to provide to Company the services more particularly described on Exhibit A attached hereto (the “Services”), and Contractor agrees to render the Services to Company.

2.Compensation and Expenses.

2.1In exchange for Contractor’s performance of Services, Company shall pay Contractor, and Contractor shall be entitled to receive, $3,200 per day, invoiced and paid on a monthly basis. Further, Contractor shall be entitled to reimbursement for travel, lodging, transportation and other reasonable, preapproved expenses incurred in the performance of its duties (collectively, the “Reimbursements”). “Reimbursements” will include but not limited to Contractors cost of lodging in Oklahoma City and local transportation in Oklahoma City while on call-out for the Company.

2.2Company shall pay all compensation due for each calendar month during which Services are performed in cash by direct deposit or wire transfer in immediately available funds to a bank account designated by Contractor. For clarification, all Reimbursements will be paid 100% in cash.

2.3Contractor shall provide to Company invoices for compensation and Reimbursements (the “Invoices”) within a reasonable time following the last day of each calendar month, and each such Invoice shall state the number of days for which Contractor is entitled to receive compensation during the relevant period and identify applicable Reimbursements (with reasonable supporting documentation) in respect of such period. Company shall remit amounts due and payable to Contractor under each Invoice no later than the end of the calendar month in which Company receives such Invoice.

3.Term.

3.1The term of this Agreement shall commence on the effective date of this Agreement and continue for a period of 5 months, unless sooner terminated as provided herein. This Agreement may be terminated, with or without cause, by either party upon thirty (30) days

Page 1 of 7

prior written notice of termination. Within ten (10) days after the effective date of termination of this Agreement, Contractor will deliver to Company any property of Company in the possession of Contractor and Company shall pay Contractor for Services actually provided by Contractor up to the effective date of the termination.

3.2Contractor’s hours will vary from week to week and be subject to the seasonal demands of the work requirements. Contractor’s total work activity is expected to remain less than 50% of a full time equivalent role.

3.3Except where limited by the confidentiality provisions of 7.1 and 7.2 and/or other provisions of this agreement where applicable, Contractor is not restricted from performing work for other clients during the term of this agreement.

4.Events of Default. Contractor shall be in default under the Agreement if it (i) fails to abide by any provision of the Agreement, (ii) becomes insolvent, (iii) makes an assignment for the benefit of creditors, (iv) is adjudicated bankrupt, (v) admits in writing its inability to pay debts as they become due, (vi) institutes any proceeding for relief of debtors or appointment of a receiver, trustee, or liquidator, or (vii) institutes a voluntary petition in bankruptcy, or (viii) fails to remove within thirty (30) days any attachment which is levied upon Company’s equipment or property.

5.Contractor’s Duties.

5.1Contractor shall perform all Services in good and workmanlike manner and in compliance with all applicable laws, rules and regulations; and subject to all of Company’s applicable safety, health and environmental rules, including its drug and alcohol policy. Additionally, during the term of this Agreement, Contractor agrees to take no actions that in any way damage the public image or reputation of Company or its affiliates or knowingly assist, in a damaging way to the Company, a competitor of Company.

5.2Contractor warrants that all Services performed by Contractor for or on behalf of Company, and all goods or other deliverables produced thereby, will not violate, infringe or misappropriate the rights of any third parties, including, without limitation, the copyright, trademark, patent, or the trade secrets of any third person.

6.Independent Contractor. Company and Contractor expressly agree that Contractor is an independent contractor as to all Services performed under this Agreement and that Contractor shall not be deemed for any purpose to be an employee, agent, servant, or representative of Company. Contractor shall be solely responsible for any and all employee benefit plans, taxes and insurance in respect of Contractor’s personnel. Contractor shall not be authorized to act or appear to act as agents or representatives of Company, whether in performing the Services or otherwise. If the performance of the Services shall include the use by Contractor of Company’s facilities, equipment or other resources, such use is permitted only to the extent necessary for the performance of the Services and not for any other purpose. This Agreement does not create, and shall not be construed by the parties hereto or any third

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party as creating, any agency, partnership, joint venture, or employment relationship between the parties hereto.

7.Confidential Information.

7.1Except as otherwise provided herein, Contractor and Company agree that any and all information that is not otherwise publicly available (other than as a result of unauthorized disclosure) and is communicated by one party (“Disclosing Party”) to the other party (“Receiving Party”), including, without limitation, engineering, electrical, facility, marketing and financial information, information regarding the nature and location of the Services and the other party’s processes and procedures, whether such information be written, oral or in electronic format (“Confidential Information”) shall be confidential and shall be treated as such and held in strict confidence by Receiving Party. Confidential Information shall be used only for purposes of the Agreement by Receiving Party, and no information, including, without limitation, the provisions of the Agreement, shall be disclosed by the Receiving Party, its agents or employees, without the prior written consent of the Disclosing Party, except as may be necessary by reason of legal, accounting or regulatory requirements beyond the reasonable control of the Receiving Party. The Receiving Party shall safeguard Confidential Information with at least the same degree of care that it uses to safeguard its own confidential, proprietary, privileged and trade secret information. This Section 7.1 shall not apply to information (i) in the public domain, (ii) the Receiving Party or its agents or employees had in their respective possession prior to receiving it from the Disclosing Party (as evidenced by dated documentation), (iii) the Receiving Party or its agents or employees obtained from a third party who rightfully acquired such information, or (iv) the Receiving Party or its agents or employees independently developed without reference to the information received from the Disclosing Party (as evidenced by dated documentation). If the Receiving Party must disclose any Confidential Information pursuant to applicable law or regulation or by operation of law, the Receiving Party may disclose only such information as, in the opinion of Receiving Party’s counsel, is legally required, and provided, further, that the Receiving Party shall to the extent permissible under applicable law, provide reasonable notice to the Disclosing Party of such requirement and a reasonable opportunity to object to such disclosure. Receiving Party’s obligations under this Section 7.1 shall survive during the term of this Agreement and for a period of one year after the termination of this Agreement for any reason. Notwithstanding anything elsewhere in the Agreement, the terms of this Section 7.1 shall apply to Confidential Information amounting to a trade secret for as long as such information remains a trade secret under applicable law and shall survive the termination of the Agreement.

7.2Contractor agrees that it will not buy or sell the securities or options on the securities of Company in the event Contractor possesses any material nonpublic information about Company. Contractor agrees that trading in the stock or options of Company based on non-public information (whether information about Company or other companies) is a breach of this Agreement. Contractor shall not sell short any stock of Company at any time during the term of this Agreement.

Page 3 of 7

8.Deliverables. The results of the Services, including without limitation reports, user manuals, designs, findings, evaluations, data and written material (collectively, the "Deliverables"), shall be considered works made for hire under the United States or other applicable copyright laws and shall become the exclusive property of Company upon payment of Contractor's invoices associated with each such Deliverable. In the event any such Deliverables do not fall within the specifically enumerated works that constitute works made for hire under the United States or other applicable copyright laws, Contractor expressly assigns all right, title and interest worldwide in and to such Deliverables to Company, including, without limitation, all copyrights, patent rights, trade secrets, trademarks, moral rights and all other applicable proprietary and intellectual property rights. If Contractor has any rights to the Deliverables that cannot be assigned to Company, Contractor unconditionally and irrevocably: (i) waives the enforcement of such rights; and (ii) grants to Company during the term of such rights, an exclusive, irrevocable, perpetual, worldwide, royalty-free license to reproduce, create derivative works of, distribute, publicly perform and publicly display such works, by all means now known or later developed, with the right to sublicense such rights. Company shall be responsible for its use of the Deliverables and for ensuring that the Deliverables meet Company’s requirements.

9.Indemnification.

9.1Contractor shall defend; shall release, discharge, and relinquish; and shall indemnify, protect and hold harmless Company, its parent, subsidiary and affiliated companies, its and their co-lessees, partners, joint venturers, co-owners, contractors (other than any member of Contractor Group (defined below)), and its and their officers, directors, employees, representatives and agents, and the successors, heirs, and assigns of any of the foregoing (collectively, “Company Group”) from and against any and all losses, claims, damages (including, without limitation, punitive damages), causes of action, fines, penalties, costs (including court costs and attorneys’ fees), suits, and liabilities of any and every kind whatsoever to the extent solely attributable to Contractor’s gross negligence, bad faith or willful misconduct in performing the Services. Notwithstanding anything to the contrary herein, Contractor’s liability under this Section 9.1 shall not exceed the aggregate amount of compensation actually paid to and received by Contractor pursuant to Section 2.

9.2The Company agrees to indemnify and hold harmless Contractor and its members, managers, officers, directors, employees, representatives and agents, and the successors, heirs, and assigns of any of the foregoing (collectively, the “Contractor Group”), from and against any and all losses, claims, damages (including, without limitation, punitive damages), causes of action, fines, penalties, costs (including court costs and attorneys’ fees), suits, and liabilities of any and every kind whatsoever to the extent related to or arising in any manner out of any activities performed or services furnished pursuant to the Agreement (collectively, “Indemnified Activities”), except for any Indemnified Activities for which Company Group is entitled to indemnification under Section 9.1.

10.Miscellaneous. Company and Contractor further agree as follows:

Page 4 of 7

10.1Notices: All notices, statements or other communications required or permitted between Company and Contractor shall be in writing and shall be considered as having been given if delivered by mail, courier, hand delivery, facsimile or email to the other party at the designated physical address, facsimile number or email address. Notices shall be delivered as follows:

If to Company:

SandRidge Energy

R. Scott Griffin

Senior Vice President – People & Culture

123 Robert S. Kerr Avenue

Oklahoma City, OK 73102

Fax: 405-429-5967

Email: sgriffin@sandridgeenergy.com

If to Contractor:

10.2Assignment. Contractor acknowledges that this Agreement and the Services provided are unique and personal. Therefore, Contractor may not assign any rights or delegate any duties or obligations under this Agreement without the prior written consent of Company. Company may assign this Agreement upon notice to Contractor. Any assignment made in contravention of this Section 10.2 shall be null and void for all purposes. To the extent that there are successors or assigns permitted under this Section 10.2, this Agreement shall be binding on and inure to the benefit of the parties and their respective successors and assigns.

10.3Entire Agreement; Amendments. THIS AGREEMENT SETS FORTH THE ENTIRE AGREEMENT BETWEEN CONTRACTOR AND COMPANY WITH RESPECT TO ITS SUBJECT MATTER. ALL PRIOR NEGOTIATIONS AND DEALINGS REGARDING THE SUBJECT MATTER HEREOF ARE SUPERSEDED BY AND MERGED INTO THIS AGREEMENT. No amendment, modification or revision of this Agreement shall be effective unless made in writing and signed by authorized representatives of both parties who have actual authority to amend, modify or revise this Agreement.

10.4Non-Solicitation.The Contractor agrees that during the Non-Solicitation Period (as hereafter defined), the Contractor will not directly, either personally or by or through his/her agent, on behalf of himself/herself or on behalf of any other individual, association or entity, (i) use any of the Confidential Information for the purposes of calling on any established

Page 5 of 7

customer or competitor of the Company or soliciting or inducing any of such customers or competitors to acquire, or providing to any of such customers or competitors, any product or service provided by the Company or any affiliate or subsidiary of the Company or (ii) solicit, divert or attempt to solicit or divert any person or entity who, to the knowledge of Contractor, has been identified and contacted by the Company, either directly or through such entity’s agent(s), with respect to a possible acquisition by, or transaction with, the Company. For the purposes hereof, the term “Non-Solicitation Period” shall mean a period of one year from the date this Agreement is terminated.

10.5Non-Interference.The Contractor and Company agree that during the Non-Interference Period (as hereafter defined) neither party will, directly or indirectly, either on its own behalf or on behalf of any other individual, association or entity, by or through its agent, hire, solicit or seek to hire any existing employee or subcontractor or attempt, directly or indirectly, to persuade any existing employee or subcontractor of the other party to discontinue his or her status of employment or subcontractor with such party or any affiliate or subsidiary of such party. For the purposes hereof, the term “Non-Interference Period” shall mean a period of one year from the date this Agreement is terminated.

10.6Severability. In the event any provision of this Agreement is inconsistent with, or contrary to, any applicable law, rule, or regulation, or if any provision of this Agreement is found by a court of competent jurisdiction to be invalid or unenforceable, that provision will be deemed to be modified to the extent required to comply with said law, rule, or regulation, or to make it valid and enforceable, and this Agreement, as so modified, shall remain in full force and effect. If said provision cannot be so modified, then it shall be deemed deleted and the remainder of the Agreement shall continue and remain in full force and effect.

10.7Headings. All headings used in this Agreement are solely for the purpose of convenience and shall in no manner be deemed to be a part of this Agreement or used in interpreting its terms.

10.8Amendment. Neither this Agreement, nor any of the provisions hereof can be changed, waived, discharged or terminated, except by an instrument in writing signed by the party against whom enforcement of the change, waiver, discharge or termination is sought.

10.9Governing Law/Jurisdiction and Venue. This Agreement, and all the rights and duties of the parties arising out of, in connection with, or relating in any way to the subject matter of this Agreement or the transactions contemplated by it, shall be governed by, construed, and enforced in accordance with the laws of the State of Oklahoma (excluding its conflict of laws rules which would refer to and apply the substantive laws of another jurisdiction). Any suit or proceeding hereunder shall be brought exclusively in state or federal courts located in Oklahoma City, Oklahoma. Each party consents to the personal jurisdiction of said state and federal courts and waives any objection that such courts are an inconvenient forum.

10.10No Recourse. There shall be no liability under this Agreement of, nor any recourse under this Agreement to, any officer, director, shareholder, beneficial owner, trustee,

Page 6 of 7

partner, manager, trustee, member, affiliate, employee or agent of either party to this Agreement.

10.11Waiver of Consequential Damages. NEITHER PARTY SHALL BE LIABLE TO THE OTHER PARTY FOR EXEMPLARY, PUNITIVE, TREBLE, INDIRECT OR CONSEQUENTIAL DAMAGES OR DAMAGES FOR LOST PROFITS OF ANY KIND ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED HEREBY. EACH PARTY, ON BEHALF OF ITSELF AND EACH OF ITS AFFILIATES, WAIVES ANY RIGHT TO RECOVER PUNITIVE, SPECIAL, EXEMPLARY AND CONSEQUENTIAL DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS, ARISING IN CONNECTION WITH OR WITH RESPECT TO THIS AGREEMENT.

[Signature Page Follows]

Page 7 of 7

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be signed by their respective duly authorized representatives.

CONTRACTOR:	COMPANY:
	SANDRIDGE ENERGY, INC.
By: _________________________________	By:_________________________________
Name: Randy Cooley	Name: R. Scott Griffin
	Title: SVP – People & Culture

Exhibit A

Contractor’s Services

Assisting with monthly financial statements, review of capital expenditures, lease operating expenses, preparation and filing of the annual Form 10-K and the quarterly Form 10-Q. Assisting with completion of the SEC pre-approval of the accounting treatment for the OXY transaction and the acquisition of the WTO gathering system from EIG. Working with PwC on the annual audit of the 2015 financials and the 2016 quarterly financials. Assisting SD staff with the preparation of the quarterly covenant calculations. Assisting SD staff and Julian Bott with any requested projects.

EX-21.1

Exhibit 21.1

SANDRIDGE ENERGY, INC. SUBSIDIARIES

Entity Name	State of Organization
CEBA Gathering, LLC	Delaware
Cholla Pipeline, L.P.	Texas
Integra Energy, L.L.C.	Texas
Lariat Services, Inc.	Texas
d/b/a LARCO
d/b/a Chaparral Drilling Fluids
d/b/a Hondo Heavy Haul
Piñon Gathering Company, LLC	Delaware
SandRidge CO2, LLC	Texas
SandRidge Exploration and Production, LLC	Delaware
SandRidge Holdings, Inc.	Delaware
SandRidge Midstream, Inc.	Texas
SandRidge Operating Company	Texas
SandRidge Realty, LLC	Oklahoma

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-185440, 333-177004, 333-160527, 333-155441, and 333-148299) of SandRidge Energy, Inc., of our report dated March 30, 2016 relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Oklahoma City, Oklahoma

March 30, 2016

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use by SandRidge Energy, Inc. (the “Company”), of our name and to the inclusion of information taken from the reports listed below in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, including any amendments thereto, filed with the U.S. Securities and Exchange Commission on or about March 30, 2016, as well as to the incorporation by reference thereof into the Company’s Registration Statements on Form S-8 (File Nos. 333-185440; 333-177004; 333-160527; 333-155441 and 333-148299):

December 31, 2015, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2014, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2013, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

CAWLEY, GILLESPIE & ASSOCIATES, INC.

J. Zane Meekins                

Executive Vice President

Fort Worth, Texas

March 30, 2016

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use by SandRidge Energy, Inc. (the “Company”), of our name and to the inclusion of information taken from the reports listed below in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the U.S. Securities and Exchange Commission on or about March 30, 2016, as well as to the incorporation by reference thereof into the Company’s Registration Statements on Form S-8 (File Nos. 333-185440; 333-177004; 333-160527; 333-155441 and 333-148299):

December 31, 2015, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2014, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

December 31, 2013, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:    /s/ C.H. (Scott) Rees III, P.E.    

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

Dallas, Texas

March 30, 2016

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

EX-23.4

Exhibit 23.4

621 SEVENTEENTH STREET, SUITE 1550        DENVER, COLORADO 80293            (303) 623-9147

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the use by SandRidge Energy, Inc. (the “Company”), of our name and to the inclusion of information taken from the reports listed below in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the U.S. Securities and Exchange Commission on or about March 30, 2016, as well as to the incorporation by reference thereof into the Company’s Registration Statements on Form S-8 (File Nos. 333-185440; 333-177004; 333-160527; 333-155441 and 333-148299):

December 31, 2015, SandRidge Energy, Inc. Interest in Certain Properties located in the United States — SEC Price Case

RYDER SCOTT COMPANY, L.P.

Denver, Colorado

March 30, 2016

1100 LOUISIANA, SUITE 4600    HOUSTON, TEXAS 77002-5218    TEL (713) 651-9191    FAX (713) 651-0849

1015 4^TH STREET S.W. SUITE 600    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

EX-31.1

Exhibit 31.1

Certification of the Company’s Chief Executive Officer Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, James D. Bennett, certify that:

1. I have reviewed this annual report on Form 10-K of SandRidge Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ James D. Bennett

James D. Bennett

President and Chief Executive Officer

Date: March 30, 2016

EX-31.2

Exhibit 31.2

Certification of the Company’s Chief Financial Officer Pursuant to

Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241)

I, Julian Bott, certify that:

1. I have reviewed this annual report on Form 10-K of SandRidge Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Julian Bott

Julian Bott

Executive Vice President and Chief Financial Officer

Date: March 30, 2016

EX-32.1

Exhibit 32.1

Certification of the Company’s Chief Executive Officer and Chief Financial Officer Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350)

Pursuant to 18 U.S.C. § 1350, the undersigned officers of SandRidge Energy, Inc. (the “Company”), hereby certify that the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 (the “Report”), fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934 and that the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ James D. Bennett

James D. Bennett

President and Chief Executive Officer

March 30, 2016

/s/ Julian Bott

Julian Bott

Executive Vice President and Chief Financial Officer

March 30, 2016

EX-99.1

Exhibit 99.1

February 8, 2016

Mr. Lance J. Galvin

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma 73102

Re:    Evaluation Summary

SandRidge Energy, Inc. Interests

Proved Reserves

As of January 1, 2016    

Dear Mr. Galvin:

As requested, we are submitting our estimates of proved reserves and our forecasts of the resulting economics attributable to the SandRidge Energy, Inc. (“SandRidge”) interests in certain oil and gas properties located in Kansas and Oklahoma. These reserves include those from its consolidated subsidiaries, SandRidge Mississippian Trust I and SandRidge Mississippian Trust II. It is our understanding that the proved reserves estimated in this report constitute approximately 78 percent of all proved reserves owned by SandRidge. This report, completed on February 8, 2016, has been prepared for use in filings with the U.S. Securities and Exchange Commission by SandRidge.

Composite reserve estimates and economic forecasts for the proved reserves are summarized below:

		Proved	Proved
		Developed	Developed	Proved
		Producing	Non-Producing	Undeveloped	Proved
Net Reserves
Oil/Condensate	- Mbbl	33,195	113	8,013	41,321
Gas	- MMcf	788,759	1,869	134,499	925,127
NGL	- Mbbl	48,883	0	7,715	56,598
Revenue
Oil/Condensate	- M$	1,579,269	5,244	381,413	1,965,927
Gas	- M$	1,473,981	3,001	250,153	1,727,135
NGL	- Mbbl	614,518	0	97,471	711,990
Operating Income (BFIT)	- M$	2,040,314	3,870	283,421	2,327,604
Discounted @ 10%	- M$	1,037,748	2,060	81,231	1,121,039

In accordance with the Securities and Exchange Commission guidelines, the operating income (BFIT) has been discounted at an annual rate of 10% to determine its “present worth”. The discounted

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SandRidge Energy, Inc.

Page 2

value, “present worth”, shown above should not be construed to represent an estimate of the fair market value by Cawley, Gillespie & Associates, Inc.

The annual average Henry Hub spot market gas price of $2.59 per MMBtu and the annual average Plains WTI posted oil price of $46.79 per barrel were used in this report. This average posted oil price corresponds to an average spot oil price of $50.28 per barrel. In accordance with the Securities and Exchange Commission guidelines, these prices are determined as an unweighted arithmetic average of the first-day-of-the-month price for each month of 2015. The oil and gas prices were held constant and were adjusted for gravity, heating value, quality, transportation and regional price differentials. The adjusted volume-weighted average product prices over the life of the properties are $47.58 per barrel of oil, $12.58 per barrel of NGL and $1.87 per Mcf of gas.

Operating costs were based on operating expense records of SandRidge. For non-operated properties, these costs include the overhead expenses allowed under existing joint operating agreements. Drilling and completion costs were based on estimates provided by SandRidge and reviewed for reasonableness by Cawley, Gillespie & Associates. Abandonment costs used in the report are estimates prepared by SandRidge to abandon the wells and production facilities, net of salvage value. As per the Securities and Exchange Commission guidelines, neither expenses nor investments were escalated.

The proved reserve classifications conform to criteria of the Securities and Exchange Commission. The estimates of reserves in this report have been prepared in accordance with the definitions and disclosure guidelines set forth in the Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). The reserves and economics are predicated on the regulatory agency classifications, rules, policies, laws, taxes and royalties in effect on the date of this report as noted herein. In evaluating the information at our disposal concerning this report, we have excluded from our consideration all matters as to which the controlling interpretation may be legal or accounting, rather than engineering and geoscience. Therefore, the possible effects of changes in legislation or other Federal or State restrictive actions have not been considered. An on-site field inspection of the properties has not been performed. The mechanical operation or conditions of the wells and their related facilities have not been examined nor have the wells been tested by Cawley, Gillespie & Associates, Inc. Possible environmental liability related to the properties has not been investigated nor considered.

The reserves were estimated using a combination of the production performance, volumetric and analogy methods, in each case as we considered to be appropriate and necessary to establish the conclusions set forth herein. All reserve estimates represent our best judgment based on data available at the time of preparation and assumptions as to future economic and regulatory conditions. It should be realized that the reserves actually recovered, the revenue derived therefrom and the actual cost incurred could be more or less than the estimated amounts.

The reserve estimates were based on interpretations of factual data furnished by SandRidge. Ownership interests were supplied by SandRidge and were accepted as furnished. To some extent, information from public records has been used to check and/or supplement these data. The basic engineering and geological data were utilized subject to third party reservations and qualifications. Nothing has come to our attention, however, that would cause us to believe that we are not justified in relying on such data.

Cawley, Gillespie & Associates, Inc. is independent with respect to SandRidge as provided in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated

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by the Society of Petroleum Engineers (“SPE Standards”). Neither Cawley, Gillespie & Associates, Inc. nor any of its employees has any interest in the subject properties. Neither the employment to make this study nor the compensation is contingent on the results of our work or the future production rates for the subject properties.

Our work-papers and related data are available for inspection and review by authorized parties. The technical person responsible for the preparation of this report meets or exceeds the education, training, and experience requirements set forth in the SPE Standards.

Respectfully submitted,

CAWLEY, GILLESPIE & ASSOCIATES, INC.

Texas Registered Engineering Firm F-693

JZM:rtp

EX-99.2

Exhibit 99.2

January 27, 2016

Mr. Lance J. Galvin

SandRidge Energy, Inc.

123 Robert S. Kerr Avenue

Oklahoma City, Oklahoma 73102

Dear Mr. Galvin:

In accordance with your request, we have estimated the proved developed reserves and future revenue, as of December 31, 2015, to the SandRidge Energy, Inc. (SandRidge) interest in certain oil and gas properties located in Texas. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 4 percent of all proved reserves owned by SandRidge. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, except that future income taxes are excluded and, as requested, per-well overhead expenses are excluded. Definitions are presented immediately following this letter. This report has been prepared for SandRidge's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the SandRidge interest in these properties, as of December 31, 2015, to be:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	10,799.5	1,271.8	3,936.1	170,083.6	108,220.1
Proved Developed Non-Producing	15.8	0.0	12.2	8.4	38.2
Total Proved Developed	10,815.3	1,271.8	3,948.3	170,092.0	108,258.4

Totals may not add because of rounding.

The oil volumes shown include crude oil only. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed reserves. As requested, proved undeveloped reserves that exist for these properties have not been included. No study was made to determine whether probable and

possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is SandRidge's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for SandRidge's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2015. For oil and NGL volumes, the average West Texas Intermediate posted price of $46.79 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted for energy content, transportation fees, and market differentials. The adjusted product prices of $47.35 per barrel of oil, $14.60 per barrel of NGL, and $1.798 per MCF of gas are held constant throughout the lives of the properties.

Operating costs used in this report are based on operating expense records of SandRidge, the operator of the properties, and include only direct lease- and field-level costs. Operating costs have been divided into per-well costs and per-unit-of-production costs. As requested, these costs do not include the per-well overhead expenses allowed under joint operating agreements, nor do they include the headquarters general and administrative overhead expenses of SandRidge. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by SandRidge and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are SandRidge's estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the SandRidge interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on SandRidge receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by SandRidge, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well location maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from SandRidge and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Gregory S. Cohen, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2013 and has over 14 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:        

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

/s/ Gregory S. Cohen

By:    

Gregory S. Cohen, P.E. 117412

Petroleum Engineer

Date Signed: January 27, 2016

GSC:CLM

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field

Definitions - Page 2 of 7

which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

Definitions - Page 3 of 7

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating

Definitions - Page 4 of 7

costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Definitions - Page 5 of 7

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a.    Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b.    Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a.    Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b.    Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c.    Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d.    Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e.    Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f.    Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable

Definitions - Page 6 of 7

holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

Ù    The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

Ù    The company's historical record at completing development of comparable long-term projects;

Ù    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

Ù    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

Ù    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7

EX-99.3

Exhibit 99.3

SandRidge Energy, Inc.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2015

Scott Wilson, P.E., MBA

Colorado License No. 36112

Senior Vice President

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (303) 623-4258
621 SEVENTEENTH STREET SUITE 1550	DENVER, COLORADO 80293	TELEPHONE (303) 623-9147

January 26, 2016

SandRidge Energy, Inc.

123 Robert S. Kerr

Oklahoma City, OK 73102

Gentlemen:

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of SandRidge Energy, Inc. (SandRidge) as of December 31, 2015. The subject properties are located in the state of Colorado. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 26, 2016 and presented herein, was prepared for public disclosure by SandRidge in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of SandRidge’s total net proved reserves as of December 31, 2015. Based on information provided by SandRidge, the third party estimate conducted by Ryder Scott addresses 29 percent of the total proved net oil reserves, 4 percent of the total proved net NGL reserves and 1 percent of the total proved net gas reserves of SandRidge. When put in discounted cash flow terms, the reserve values evaluated represent 1 percent of the FNI discounted at 10 percent.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2015, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

1100 LOUISIANA STREET, SUITE 4600     HOUSTON, TEXAS 77002-5294    TEL (713) 651-9191    FAX (713) 651-0849

SUITE 600, 1015 4TH STREET, S.W.    CALGARY, ALBERTA T2R 1J4    TEL (403) 262-2799    FAX (403) 262-2790

Sandridge Energy, Inc.

January 26, 2016

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

SandRidge Energy, Inc.

As of December 31, 2015

	Proved
	Developed Producing		Undeveloped		Total Proved
Net Remaining Reserves
Oil/Condensate – Barrels	1,188,251		21,258,743		22,446,994
Plant Products - Barrels	189,244		2,270,876		2,460,120
Gas - MMCF	1,227		14,725		15,952
Income Data (M$)
Future Gross Revenue		$50,138		$867,686		$917,824
Deductions	23,311		719,781		743,092
Future Net Income (FNI)		$26,827		$147,905	$	174,732
Discounted FNI @ 10%		$16,558	$	1,871	$	18,429

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of SandRidge and Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon proved reserves account for approximately 97 percent of total future gross revenue while gas reserves account for the remaining 3 percent of future revenue.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Sandridge Energy, Inc.

January 26, 2016

Page 3

	Discounted Future Net Income (M$)
	As of December 31, 2015
Discount Rate		Total
Percent		Proved
15		$(14,392)
20		$(34,762)
25		$(47,831)
30		$(56,368)

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At SandRidge’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Sandridge Energy, Inc.

January 26, 2016

Page 4

construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

SandRidge’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which SandRidge owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. All of the proved producing reserves attributable to

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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January 26, 2016

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producing wells and/or reservoirs were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis, material balance and/or reservoir simulation which utilized extrapolations of historical production and pressure data available through November 2015 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by SandRidge or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved undeveloped reserves included herein were estimated by analogy, the volumetric method, reservoir simulation, or a combination of methods. The volumetric analysis utilized pertinent well data furnished to Ryder Scott by SandRidge or which we have obtained from public data sources that were available through November 2015. The data utilized from the analogues in addition to well data incorporated into our volumetric analysis were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

SandRidge has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by SandRidge with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by SandRidge. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Sandridge Energy, Inc.

January 26, 2016

Page 6

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by SandRidge. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

SandRidge furnished us with the above mentioned average prices in effect on December 31, 2015. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic areas included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by SandRidge.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
	Oil	WTI Cushing	$50.28/Bbl	$39.59/Bbl
United States	Plant Products	Mt. Belvieu	$19.90/Bbl	$14.04/Bbl
	Gas	Henry Hub	$2.58/MMBTU	$2.06/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Sandridge Energy, Inc.

January 26, 2016

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Costs

Operating costs for the leases and wells in this report were furnished by SandRidge and include only those costs directly applicable to the leases or wells. The operating costs furnished were reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by SandRidge and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. SandRidge estimates that abandonment costs generally equal salvage values for the properties reviewed in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for SandRidge’s estimate. SandRidge uses a series of several cost entries spread over a period in which a well is drilled and completed to more accurately reflect cash flows. For this reason, wells that are spudded in one period may have lagging costs that spill over into the next period and some wells that are on production may show some final costs associated with site reclamation and other costs that may occur after production starts.

The proved undeveloped reserves in this report have been incorporated herein in accordance with SandRidge’s plans to develop these reserves as of December 31, 2015.  The implementation of SandRidge’s development plans as presented to us and incorporated herein is subject to the approval process adopted by SandRidge’s management.  As the result of our inquiries during the course of preparing this report, SandRidge has informed us that the development activities included herein have been subjected to and received the internal approvals required by SandRidge’s management at the appropriate local, regional and/or corporate level.  In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to SandRidge.   Additionally, SandRidge has informed us that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.  While these plans could change from those under existing economic conditions as of December 31, 2015, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by SandRidge were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Sandridge Energy, Inc.

January 26, 2016

Page 8

or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to SandRidge. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by SandRidge.

SandRidge makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, SandRidge has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Forms S-3 and/or S-8 of SandRidge of the references to our name as well as to the references to our third party report for SandRidge, which appears in the December 31, 2015 annual report on Form 10-K of SandRidge. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by SandRidge.

We have provided SandRidge with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by SandRidge and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Scott J. Wilson, P.E., MBA

Colorado License No. 36112

Senior Vice President

SJW (DPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Sandridge Energy, Inc.

January 26, 2016

Page 1

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Scott James Wilson was the primary technical person responsible for the estimate of the reserves, future production, and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2000, is a Senior Vice President and Technical Advisor responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Atlantic Richfield Company. For more information regarding Mr. Wilson's geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Company/Employees.

Mr. Wilson earned a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines in 1983 and an MBA in Finance from the University of Colorado in 1985, graduating from both with High Honors. He is a registered Professional Engineer by exam in the States of Alaska, Colorado, Texas, and Wyoming. He is also an active member of the Society of Petroleum Engineers; serving as co-Chairman of the SPE Reserves and Economics Technology Interest Group, and Gas Technology Editor for SPE's Journal of Petroleum Technology. He is a member and past chairman of the Denver section of the Society of Petroleum Evaluation Engineers. Mr. Wilson has published several technical papers, one published book chapter and another in SPEE monograph 4 to be published in 2016. He is the primary inventor on three US patents.

In addition to gaining experience and competency through prior work experience, several state Boards of Professional Engineers require a minimum number of hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills as part of his registration in four states. As part of his continuing education, Mr. Wilson attends internally presented training as well as public forums relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, and Final Rule released January 14, 2009 in the Federal Register. Mr. Wilson attends additional hours of formalized external training covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Mar. 23, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	SANDRIDGE ENERGY INC
Entity Central Index Key	0001349436
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Amendment Flag	false
Entity Public Float			$ 447.7
Entity Common Stock, Shares Outstanding		718,226,053

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 435,588	$ 181,253
Accounts receivable, net	127,387	330,077
Derivative contracts	84,349	291,414
Prepaid expenses	6,833	7,981
Other current assets	19,931	21,193
Total current assets	674,088	831,918
Oil and natural gas properties, using full cost method of accounting
Proved (includes development and project costs excluded from amortization of $34.6 million and $53.6 million at December 31, 2015 and 2014, respectively)	12,529,681	11,707,147
Unproved	363,149	290,596
Less: accumulated depreciation, depletion and impairment	(11,149,888)	(6,359,149)
Net oil and natural gas properties capitalized costs	1,742,942	5,638,594
Other property, plant and equipment, net	491,760	576,463
Derivative contracts	0	47,003
Other assets	82,365	165,247
Total assets	2,991,155	7,259,225
Current liabilities
Accounts payable and accrued expenses	428,417	683,392
Derivative contracts	573	0
Asset retirement obligations	8,399	0
Deferred tax liability	0	95,843
Other current liabilities	0	5,216
Total current liabilities	437,389	784,451
Long-term debt	3,631,506	3,195,436
Asset retirement obligations	95,179	54,402
Other long-term obligations	14,814	15,116
Total liabilities	$ 4,178,888	$ 4,049,405
Commitments and contingencies (Note 15)
Preferred stock, $0.001 par value, 50,000 shares authorized
Common stock, $0.001 par value; 1,800,000 shares authorized, 635,584 issued and 633,471 outstanding at December 31, 2015; 800,000 shares authorized, 485,932 issued and 484,819 outstanding at December 31, 2014	$ 630	$ 477
Additional paid-in capital	5,301,136	5,204,024
Additional paid-in capital—stockholder receivable	(1,250)	(2,500)
Treasury stock, at cost	(5,742)	(6,980)
Accumulated deficit	(6,992,697)	(3,257,202)
Total SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,697,917)	1,937,825
Noncontrolling interest	510,184	1,271,995
Total stockholders’ (deficit) equity	(1,187,733)	3,209,820
Total liabilities and stockholders’ (deficit) equity	2,991,155	7,259,225
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015 and 2014; aggregate liquidation preference of $265,000
Preferred stock, $0.001 par value, 50,000 shares authorized
Preferred stock	3	3
7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000; 3,000 shares issued and outstanding at December 31, 2014, aggregate liquidation preference of $300,000
Preferred stock, $0.001 par value, 50,000 shares authorized
Preferred stock	$ 3	$ 3

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Development and project costs excluded from amortization	$ 34,600	$ 53,600
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized (in shares)	50,000,000	50,000,000
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	1,800,000,000	800,000,000
Common stock, issued (in shares)	635,584,000	485,932,000
Common stock, outstanding (in shares)	633,471,000	484,819,000
8.5% Convertible perpetual preferred stock; 2,650 shares issued and outstanding at December 31, 2015 and 2014; aggregate liquidation preference of $265,000
Preferred stock, dividend rate, percentage	8.50%	8.50%
Preferred stock, shares issued (in shares)	2,650,000	2,650,000
Preferred stock, shares outstanding (in shares)	2,650,000	2,650,000
Preferred stock, aggregate liquidation preference	$ 265,000	$ 265,000
7.0% Convertible perpetual preferred stock; 2,770 shares issued and outstanding at December 31, 2015, aggregate liquidation preference of $277,000; 3,000 shares issued and outstanding at December 31, 2014, aggregate liquidation preference of $300,000
Preferred stock, dividend rate, percentage	7.00%	7.00%
Preferred stock, shares issued (in shares)	2,770,000	3,000,000
Preferred stock, shares outstanding (in shares)	2,770,000	3,000,000
Preferred stock, aggregate liquidation preference	$ 277,000	$ 300,000

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Oil, natural gas and NGL	$ 707,434	$ 1,420,879	$ 1,820,278
Drilling and services	22,124	76,088	66,586
Midstream and marketing	33,809	55,658	58,304
Construction contract	0	0	23,349
Other	5,342	6,133	14,871
Total revenues	768,709	1,558,758	1,983,388
Expenses
Production	308,701	346,088	516,427
Production taxes	15,440	31,731	32,292
Cost of sales	24,394	56,155	57,118
Midstream and marketing	26,819	49,905	53,644
Construction contract	0	0	23,349
Depreciation and depletion—oil and natural gas	319,913	434,295	567,732
Depreciation and amortization—other	47,382	59,636	62,136
Accretion of asset retirement obligations	4,477	9,092	36,777
Impairment	4,534,689	192,768	26,280
General and administrative	137,715	113,991	207,920
Employee termination benefits	12,451	8,874	122,505
(Gain) loss on derivative contracts	(73,061)	(334,011)	47,123
Loss on settlement of contract	50,976	0	0
Loss on sale of assets	1,491	10	399,086
Total expenses	5,411,387	968,534	2,152,389
(Loss) income from operations	(4,642,678)	590,224	(169,001)
Other (expense) income
Interest expense	(321,421)	(244,109)	(270,234)
Gain (loss) on extinguishment of debt	641,131	0	(82,005)
Other income, net	2,040	3,490	12,445
Total other income (expense)	321,750	(240,619)	(339,794)
(Loss) income before income taxes	(4,320,928)	349,605	(508,795)
Income tax expense (benefit)	123	(2,293)	5,684
Net (loss) income	(4,321,051)	351,898	(514,479)
Less: net (loss) income attributable to noncontrolling interest	(623,506)	98,613	39,410
Net (loss) income attributable to SandRidge Energy, Inc.	(3,697,545)	253,285	(553,889)
Preferred stock dividends	37,950	50,025	55,525
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$ (3,735,495)	$ 203,260	$ (609,414)
(Loss) earnings per share
Basic (in dollars per share)	$ (7.16)	$ 0.42	$ (1.27)
Diluted (in dollars per share)	$ (7.16)	$ 0.42	$ (1.27)
Weighted average number of common shares outstanding
Basic (in shares)	521,936	479,644	481,148
Diluted (in shares)	521,936	499,743	481,148

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Consolidated Statements of Changes in Stockholders’ Equity (Deficit) - USD ($) shares in Thousands, $ in Thousands	Total	Convertible Perpetual Preferred Stock	Common Stock	Additional Paid-In Capital	Treasury Stock	Accumulated Deficit	Non-controlling Interest
Beginning Balance at Dec. 31, 2012	$ 3,862,455	$ 8	$ 476	$ 5,228,019	$ (8,602)	$ (2,851,048)	$ 1,493,602
Beginning Balance (in shares) at Dec. 31, 2012		7,650
Beginning Balance (in shares) at Dec. 31, 2012			490,359
Increase (Decrease) in Stockholders' Equity
Sale of royalty trust units	28,985			7,289			21,696
Distributions to noncontrolling interest owners	(206,470)						(206,470)
Contributions from noncontrolling interest owners	1,579						1,579
Purchase of treasury stock	(30,126)				(30,126)
Retirement of treasury stock	0			(30,126)	30,126
Stock purchases/distributions, net of distributions/purchases - retirement plans (in shares)			(99)
Stock purchases/distributions, net of distributions/purchases - retirement plans	(435)			(267)	(168)
Stock-based compensation	88,397			88,397
Stock-based compensation excess tax provision	(4)			(4)
Payment received on shareholder receivable	1,250			1,250
Issuance of restricted stock awards, net of cancellations (in shares)			30
Issuance of restricted stock awards, net of cancellations	0		$ 7	(7)
Common stock issued for debt	0
Net (loss) income	(514,479)					(553,889)	39,410
Convertible perpetual preferred stock dividends	(55,525)					(55,525)
Ending Balance (in shares) at Dec. 31, 2013		7,650
Ending Balance (in shares) at Dec. 31, 2013			490,290
Ending Balance at Dec. 31, 2013	3,175,627	$ 8	$ 483	5,294,551	(8,770)	(3,460,462)	1,349,817
Increase (Decrease) in Stockholders' Equity
Sale of royalty trust units	22,119			4,091			18,028
Distributions to noncontrolling interest owners	(193,807)						(193,807)
Purchase of treasury stock	(6,373)				(6,373)
Retirement of treasury stock	0			(6,373)	6,373
Stock purchases/distributions, net of distributions/purchases - retirement plans (in shares)			206
Stock purchases/distributions, net of distributions/purchases - retirement plans	9			(1,781)	1,790
Stock-based compensation	23,665			23,665
Stock-based compensation excess tax benefit	14			14
Payment received on shareholder receivable	1,250			1,250
Issuance of restricted stock awards, net of cancellations (in shares)			3,311
Issuance of restricted stock awards, net of cancellations	0		$ 3	(3)
Common stock issued for debt	0
Acquisition of ownership interest	(2,730)			(2,074)			(656)
Repurchase of common stock (in shares)			(27,411)
Repurchase of common stock	(111,827)		$ (27)	(111,800)
Conversion of preferred stock to common stock (in shares)		(2,000)	18,423
Conversion of preferred stock to common stock	0	$ (2)	$ 18	(16)
Net (loss) income	351,898					253,285	98,613
Convertible perpetual preferred stock dividends	$ (50,025)					(50,025)
Ending Balance (in shares) at Dec. 31, 2014		5,650
Ending Balance (in shares) at Dec. 31, 2014	484,819		484,819
Ending Balance at Dec. 31, 2014	$ 3,209,820	$ 6	$ 477	5,201,524	(6,980)	(3,257,202)	1,271,995
Increase (Decrease) in Stockholders' Equity
Distributions to noncontrolling interest owners	(138,305)						(138,305)
Purchase of treasury stock	(2,428)				(2,428)
Retirement of treasury stock	0			(2,428)	2,428
Stock purchases/distributions, net of distributions/purchases - retirement plans (in shares)			(1,000)
Stock purchases/distributions, net of distributions/purchases - retirement plans	322			(916)	1,238
Stock-based compensation	21,123			21,123
Payment received on shareholder receivable	1,250			1,250
Issuance of restricted stock awards, net of cancellations (in shares)			1,514
Issuance of restricted stock awards, net of cancellations	$ 0		$ 5	(5)
Common stock issued for debt (in shares)	92,800		120,881
Common stock issued for debt	$ 63,299		$ 121	63,178
Conversion of preferred stock to common stock (in shares)		(230)	2,968
Conversion of preferred stock to common stock	0		$ 3	(3)
Net (loss) income	(4,321,051)					(3,697,545)	(623,506)
Convertible perpetual preferred stock dividends (in shares)			24,289
Convertible perpetual preferred stock dividends	$ (21,763)		$ 24	16,163		(37,950)
Ending Balance (in shares) at Dec. 31, 2015		5,420
Ending Balance (in shares) at Dec. 31, 2015	633,471		633,471
Ending Balance at Dec. 31, 2015	$ (1,187,733)	$ 6	$ 630	$ 5,299,886	$ (5,742)	$ (6,992,697)	$ 510,184

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$ (4,321,051)	$ 351,898	$ (514,479)
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	367,295	493,931	629,868
Accretion of asset retirement obligations	4,477	9,092	36,777
Impairment	4,534,689	192,768	26,280
Debt issuance costs amortization	11,884	9,425	10,091
Amortization of discount, net of premium, on long-term debt	3,130	529	1,036
(Gain) loss on extinguishment of debt	(641,131)	0	82,005
Write off of debt issuance costs	7,108	0	0
Deferred income tax provision	0	0	3,842
Loss on long-term debt derivatives	10,377	0	0
Cash paid for early conversion of convertible notes	(32,741)	0	0
(Gain) loss on derivative contracts	(73,061)	(334,011)	47,123
Cash received (paid) on settlement of derivative contracts	327,702	11,796	(5,879)
Loss on settlement of contract	50,976	0	0
Cash paid on settlement of contract	(24,889)	0	0
Loss on sale of assets	1,491	10	399,086
Stock-based compensation	18,380	19,994	85,270
Other	1,351	407	3,929
Changes in operating assets and liabilities increasing (decreasing) cash
Receivables	201,907	(63,492)	90,048
Costs in excess of billings	0	0	11,229
Prepaid expenses	1,148	9,549	(7,934)
Other current assets	12,710	3,164	(3,269)
Other assets and liabilities, net	2,239	(1,132)	5,777
Accounts payable and accrued expenses	(86,470)	(66,492)	101,453
Asset retirement obligations	(3,984)	(16,322)	(133,623)
Net cash provided by operating activities	373,537	621,114	868,630
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment	(879,201)	(1,553,332)	(1,496,731)
Acquisitions of assets	216,943	18,384	17,028
Proceeds from sale of assets	56,504	714,475	2,584,115
Net cash (used in) provided by investing activities	(1,039,640)	(857,241)	1,070,356
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings	2,065,000	0	0
Repayments of borrowings	(939,466)	0	(1,115,500)
Premium on debt redemption	0	0	(61,997)
Debt issuance costs	(53,244)	(3,947)	(91)
Proceeds from the sale of royalty trust units	0	22,119	28,985
Noncontrolling interest distributions	(138,305)	(193,807)	(206,470)
Noncontrolling interest contributions	0	0	1,579
Acquisition of ownership interest	0	(2,730)	0
Stock-based compensation excess tax benefit	0	14	(4)
Purchase of treasury stock	(3,535)	(8,702)	(32,976)
Repurchase of common stock	0	(111,827)	0
Dividends paid—preferred	(11,262)	(55,525)	(55,525)
Payment received on shareholder receivable	1,250	1,250	1,250
Cash (paid) received on settlement of financing derivative contracts	0	(44,128)	6,660
Net cash provided by (used in) financing activities	920,438	(397,283)	(1,434,089)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	254,335	(633,410)	504,897
CASH AND CASH EQUIVALENTS, beginning of year	181,253	814,663	309,766
CASH AND CASH EQUIVALENTS, end of year	$ 435,588	$ 181,253	$ 814,663

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Nature of Business. SandRidge Energy, Inc. is an energy 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 the Rockies in Colorado. The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater gathering and disposal system, an electrical transmission system and a drilling and related oilfield services business.

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

Going Concern. The Company depends on cash flows from operating activities and, as necessary and available, borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Additionally, the Company historically has used 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.

The market price for oil, natural gas and natural gas liquids (“NGLs”) decreased significantly beginning in the fourth quarter of 2014, continuing throughout 2015, and into 2016. The decrease in the market price for production directly reduces the Company’s cash flow from operations and indirectly impacts its other potential sources of funds described above. As discussed in Note 22, the Company borrowed all of its remaining available capacity under the senior credit facility in January 2016 and in March 2016, the lenders under the senior credit facility elected to reduce the borrowing base to $340.0 million. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties. Lower market prices for production may result in further reductions to the borrowing base under the senior credit facility or higher borrowing costs from other potential sources of financing as the Company’s borrowing capacity and borrowing costs are generally related to the value of the Company’s estimated proved reserves. The weakness in pricing may also impact the Company’s ability to negotiate asset monetizations at acceptable prices.

As a result of the impacts to the Company’s financial position resulting from declining industry conditions and in consideration of the substantial amount of long-term debt outstanding, the Company has engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its financial position or complete any strategic transactions. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern as it is currently structured.

As a result, the report of the Company’s independent registered public accounting firm that accompanies these consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern, which under the terms of the senior credit facility may result in an event of default. If the Company does not obtain a waiver of this requirement or otherwise cure this event within 30 calendar days of the issuance of these financial statements, the lenders under the senior credit facility will be able to accelerate maturity of the debt. Any acceleration of the obligations under the senior credit facility would result in a cross-default and potential acceleration of the maturity of the Company’s other outstanding long-term debt. These defaults create additional uncertainty associated with the Company’s ability to repay its outstanding long-term debt obligations as they become due and further reinforces the substantial doubt over the Company’s ability to continue as a going concern.

The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern.

Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE and the significance of the variable interest, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements. In addition to the VIEs that the Company consolidates, until October 2015, the Company also held a variable interest in another VIE that it did not consolidate 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.

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

Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; cash flow estimates used in the valuations of guarantees; impairment tests of long-lived assets; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.

Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the exploration, production and treating services for oil and natural gas. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts.

Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements.

Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5.

Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates. Additionally, the Company has derivatives related to its 8.75% Senior Secured Notes due 2020 (“Senior Secured Notes”) and its 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, “Convertible Senior Unsecured Notes”) that are recorded at fair value each reporting period. Refer to Notes 5 and 13 for further information on derivatives associated with the Company’s long-term debt.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 13 for further discussion of the Company’s derivatives.

Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized internal costs of $45.1 million, $55.4 million and $74.7 million to the full cost pool during the years ended December 31, 2015, 2014 and 2013, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.

Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If an asset or asset group is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. See Note 8 for further discussion of impairments.

Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time. During 2015, 2014 and 2013, interest of approximately $10.8 million, $14.7 million and $11.7 million, respectively, was capitalized on unproved properties that were not currently being depreciated or depleted and on which exploration activities were in progress. Additionally, interest of $3.3 million, $5.0 million and $4.9 million was capitalized in 2015, 2014 and 2013, respectively, on midstream and corporate assets which were under construction.

Debt Issuance Costs. The Company amortizes debt issuance costs related to its long-term debt as interest expense over the scheduled maturity period of the related debt. The Company includes unamortized debt issuance costs in other assets in the consolidated balance sheets. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.

Investments. Investments in marketable equity securities have been designated as available for sale and measured at fair value pursuant to the fair value option which requires unrealized gains and losses be reported in earnings.

Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 14 for further discussion of the Company’s asset retirement obligations.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $1.5 million and $1.4 million at December 31, 2015 and 2014, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

The Company accounted for its construction contract, discussed in Note 11, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract losses are recorded at the time it is determined that a loss will be incurred. Contract gains, if any, are recorded upon substantial completion of the construction project.

The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized at the time mobilization services are performed.

In general, natural gas purchased and sold by the midstream business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, since the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold.

Share-Based Compensation. The Company may grant restricted stock awards to members of its Board of Directors (the “Board”) and its employees. Such awards and the related stock-based compensation cost are measured based on the calculated fair value of the award on the grant date. The expense, net of estimated forfeitures, is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award.

The Company grants restricted stock units to members of the Board and its employees. Such awards are settled in cash, shares of Company common stock or a combination of common stock and cash. Restricted stock units vest over a maximum four-year period from the grant date and are valued based upon the Company’s stock price at each period end.

To the extent stock-based compensation cost relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statements of operations. The related excess tax benefit received upon vesting of restricted stock, if any, is reflected in the consolidated statements of cash flows as a financing activity. The related excess tax expense due upon vesting of restricted stock, if any, is reflected in the consolidated statements of cash flows as an operating activity.

Performance Unit Compensation. The Company awards performance units and performance share units, which contain a market-based performance component with cash settlement at the end of the performance period, to certain members of senior management. The Company recognizes a liability and expense for performance unit compensation for the portion earned over the requisite service period in an amount equal to the fair value of the performance units granted. Changes in the fair value of the units for which the service requirement has been met are recognized as compensation expense with a corresponding adjustment to the liability. To the extent performance unit compensation cost relates to those directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statements of operations.

Advertising Costs. The Company expenses advertising costs as incurred. Advertising and promotional costs were $0.7 million, $1.3 million, and $5.1 million, respectively, during the years ended December 31, 2015, 2014 and 2013.

Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.

The Company has elected an accounting policy in which interest and penalties on income taxes are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.

Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested restricted stock awards and restricted share units, using the treasury method, and convertible preferred stock and convertible senior notes, using the if-converted method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants is assumed to be used to repurchase shares at the average market price. Under the if-converted method, the Company assumes the conversion of the preferred stock or convertible senior notes to common stock and determines if it is more dilutive than including the preferred stock dividends or expense associated with the convertible senior notes, respectively, in the computation of income available to common stockholders. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 20 for the Company’s earnings per share calculation.

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 15 for discussion of the Company’s commitments and contingencies.

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

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

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. See Note 23 for information regarding the Company’s major customers. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect the Company’s ability to sell the oil, natural gas and NGLs it produces.

Recent Accounting Pronouncements. In April 2014, the financial accounting standards board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”, which amends the definition of a discontinued operations to elevate the threshold for a disposal transaction to qualify as a discontinued operation and requires entities to provide additional disclosures for disposal transactions that do not meet the discontinued operations criteria. The guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The guidance was adopted January 1, 2015 and had no impact for the year ended December 31, 2015.

In November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which requires the classification of all deferred tax assets and liabilities as non-current. The guidance is effective on either a prospective or retrospective basis for periods beginning after December 15, 2016, with early adoption permitted. The Company elected to adopt this guidance on a prospective basis on December 31, 2015, and as such, did not retrospectively adjust prior periods. Since the Company’s deferred tax assets and liabilities are equal and offsetting after including the effect of the valuation allowance, adoption of the guidance resulted in the elimination, for presentation purposes, of a non-current deferred tax asset and a current deferred tax liability on the accompanying consolidated balance sheet at December 31, 2015.

Recent Accounting Pronouncements Not Yet Adopted. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Certain of the provisions also amend or supersede existing guidance applicable to the recognition of a gain or loss on transfers of nonfinancial assets that are not an output of an entity’s ordinary activities, including sales of property, plant and equipment and real estate. In August, 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which defers the effective date of ASU 2014-09 to annual periods beginning after December 15, 2017, and interim periods within that reporting period. Early adoption is permitted, and either a full retrospective or modified approach may be used for adoption. The Company is currently evaluating the effect, if any, that the updated standard will have on its consolidated financial statements and related disclosures.

In August 2014, the FASB issued ASU 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The Company evaluated the effect of the guidance and it will have no impact on its related disclosures.

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

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

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-06, “Contingent Put and Call Options in Debt Instruments” which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts, which is one of the criteria for bifurcating an embedded derivative. The amendments eliminate diversity in practice in assessing embedded contingent call (put) options in debt instruments. The guidance requires adoption by application of a modified retrospective approach to existing and future debt instruments effective for fiscal years after December 15, 2016, including interim periods within those years.  Early adoption is permitted. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Years Ended December 31,
	2015			2014			2013
	(In thousands)
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(296,386	)	$	(235,793	)	$	(274,850	)
Cash (paid) received for income taxes	$	(88	)	$	1,928		$	(4,610	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	—		$	—		$	(255,000	)
Change in accrued capital expenditures	$	177,586		$	(55,557	)	$	72,848
Equity issued for debt	$	(63,299	)	$	—		$	—
Preferred stock dividends paid in common stock	$	(16,188	)	$	—		$	—
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$	(50,310	)	$	—		$	—

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2015

Acquisitions And Dispositions [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

2015 Acquisitions

Acquisition of Piñon Gathering Company, LLC. In October 2015, the Company acquired all of the assets of and terminated a gathering agreement with Piñon Gathering Company, LLC (“PGC’) for $48.0 million in cash and $78.0 million principal amount of newly issued 8.75% Senior Secured Notes due 2020 (“PGC Senior Secured Notes”). PGC owns approximately 370 miles of gathering lines supporting the natural gas production from the Company's Piñon field in the West Texas Overthrust (“WTO”). The transaction resulted in the termination of the Company’s gas gathering agreement with PGC under which it was required to compensate PGC for any throughput shortfalls below a required minimum volume. The fair value of the consideration paid by the Company, including discount attributable to the PGC Senior Secured Notes, was approximately $98.3 million and was allocated on a fair value basis between the assets acquired (approximately $47.3 million) and a loss on the termination of the gathering contract (approximately $51.0 million). See Note 4 for further discussion of the gathering agreement with PGC.

Acquisition of Rockies Properties. In December 2015, the Company acquired approximately 135,000 net acres in the North Park Basin in the Rockies, in Jackson County, Colorado. The Company paid approximately $191.1 million in cash, including post-closing adjustments, and received $3.1 million from the seller for overriding royalty interests. Also included in the acquisition were working interests in 16 wells previously drilled on the acreage.

2014 Divestiture

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 21 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 December 31, 2014, the fair value of the guarantees was approximately $5.1 million. See Note 5 for additional discussion of the determination of the guarantee’s fair value. The guarantee did not include a limit on the potential future payments for which the Company could be obligated; however, Fieldwood agreed to indemnify the Company for any costs it incurred as a result of the guarantee and to use its best efforts to pay any amounts sought from the Company by the Bureau of Ocean Energy Management (“BOEM”) that arose prior to the expiration of the guarantee. The Company did not incur any costs as a result of this guarantee and was released from the obligation during the third quarter of 2015. Additionally, Fieldwood maintained, for a period of up to one year from the closing date, restricted deposits held in escrow for plugging and abandonment obligations associated with the Gulf Properties. In the first quarter of 2015, the Company received its share of such deposits, net of any amounts payable to Fieldwood, or $12.0 million, in accordance with the terms of the sale.

The following table presents revenues and expenses, including direct operating expenses, depletion, accretion of asset retirement obligations and general and administrative expenses, for the Gulf Properties included in the accompanying consolidated statements of operations for the years ended December 31, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2014(1)		2013
Revenues	$	90,920	$	627,236
Expenses	$	63,674	$	491,991

____________________

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

2013 Divestiture

Sale of Permian Properties. On February 26, 2013, the Company sold its oil and natural gas properties in the Permian Basin area of west Texas, excluding the assets associated with the SandRidge Permian Trust area of mutual interest (the “Permian Properties”) for $2.6 billion, including certain post-closing adjustments that were finalized in the third quarter of 2013. 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. The loss is included in loss on sale of assets in the accompanying consolidated statement of operations for the year ended December 31, 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 consolidated statement of operations for the year ended December 31, 2013.

The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying consolidated statement of operations for the year ended December 31, 2013 (in thousands):

	Year Ended December 31, 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.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

Variable Interest Entities

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

Royalty Trusts

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

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

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

 ____________________

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

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

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

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

Royalty Interests. The Royalty Trusts own royalty interests in oil and natural gas wells that were either (i) conveyed to the Royalty Trusts by SandRidge concurrent with the closing of each Royalty Trust’s initial public offering or (ii) drilled within a defined area of mutual interest during a specified period of time as discussed further below. Pursuant to the agreements governing the Royalty Trusts, the Mississippian Trust I will terminate in 2030 and the Permian Trust and Mississippian Trust II will terminate in 2031. Upon termination, 50% of the royalty interests of each Royalty Trust will automatically revert to the Company, and the remaining 50% will be sold, with the proceeds distributed to the Royalty Trust unitholders.

Drilling Obligations. The Company and one of its wholly owned subsidiaries entered into a development agreement with each Royalty Trust upon conveyance of the royalty interests by the Company that obligated the Company to drill, or cause to be drilled, a specified number of wells which are also subject to the royalty interests within respective areas of mutual interest by a specified date. One of the Company’s wholly owned subsidiaries also granted to each Royalty Trust a lien on the Company’s interests in the properties where the development wells were to be drilled in order to secure the estimated amount of drilling costs for the Royalty Trust’s interests in the wells. The total amount that may be recovered by each Royalty Trust under its respective lien was proportionately reduced as the Company has drilled and completed the associated development wells. The Company fulfilled its drilling obligation to the Mississippian Trust I in the second quarter of 2013, to the Permian Trust in the fourth quarter of 2014 and to the Mississippian Trust II in the first quarter of 2015 and the related liens were automatically released.

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

Quarterly distributions declared and paid by the Royalty Trusts during the years ended December 31, 2015, 2014 and 2013 as follows (in thousands):

	Year Ended December 31,
	2015(1)		2014(2)		2013(3)
Total distributions	$	158,632	$	234,326	$	299,674
Distributions to third-party unitholders	$	138,305	$	193,807	$	206,470

____________________

(1) Subordination thresholds were not met for the Permian Trust and Mississippian Trust II’s distributions for the year ended December 31, 2015, resulting in reduced distributions to the Company on its subordinated units for this period.

(2) Subordination thresholds were not met for the Mississippian Trust I’s first or second quarter 2014 distributions, the Permian Trust’s second, third or fourth quarter 2014 distributions or for the Mississippian Trust II’s distributions for the year ended December 31, 2014, resulting in reduced distributions to the Company on its subordinated units for these periods.

(3) Subordination thresholds were not met for the Mississippian Trust I’s second, third or fourth quarter 2013 distributions, the Permian Trust’s second quarter 2013 distribution or for the Mississippian Trust II’s fourth quarter 2013 distribution, resulting in reduced distributions to the Company on its subordinated units for these periods.

See Note 22 for discussion of the Royalty Trusts’ distributions announced in January 2016.

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

Loan Commitment. Pursuant to the agreements governing the Royalty Trusts, the Company 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 the Company 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 December 31, 2015 or 2014.

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

Derivatives Agreements. The Company had a derivatives agreement with each Royalty Trust, pursuant to which the Company provided to the Royalty Trust the economic effects of certain of the Company’s derivative contracts covering production through December 31, 2015 for the Mississippian Trust I and the Mississippian Trust II and through March 31, 2015 for the Permian Trust. These agreements expired upon expiration of the underlying derivative contracts.

See Note 13 for further discussion of the derivatives agreement between the Company and each Royalty Trust.

Assets and Liabilities. Each Royalty Trust’s assets can be used to settle only that Royalty Trust’s obligations and not other obligations of the Company or another Royalty Trust. The Royalty Trusts’ creditors have no contractual recourse to the general credit of the Company. Although the Royalty Trusts are included in the Company’s consolidated financial statements, the Company’s legal interest in the Royalty Trusts’ assets is limited to its ownership of the Royalty Trusts’ units. At December 31, 2015 and 2014, $510.2 million and $1.3 billion, respectively, of noncontrolling interest in the accompanying consolidated balance sheets were attributable to the Royalty Trusts. The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying consolidated balance sheets at December 31, 2015 and 2014 consisted of the following (in thousands):

	December 31,
	2015			2014
Cash and cash equivalents(1)	$	7,824		$	9,387
Accounts receivable	4,457			17,660
Derivative contracts	—			6,589
Total current assets	12,281			33,636
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion and impairment(3)	(1,248,957		)	(284,094		)
	76,985			1,041,848
Total assets	$	89,266		$	1,075,484
Accounts payable and accrued expenses	$	1,060		$	2,852
Total liabilities	$	1,060		$	2,852

____________________

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

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

(3) Includes cumulative full cost ceiling limitation impairment of $976.2 million and $42.3 million at December 31, 2015 and 2014, respectively.

See Note 15 for discussion of the Company’s legal proceedings to which the Mississippian Trust I and Mississippian Trust II are also parties.

Sales of Common Units. During the years ended December 31, 2014 and 2013, the Company sold Royalty Trust common units it owned in transactions exempt from registration pursuant to Rule 144 under the Securities Act for proceeds of approximately $22.1 million and $29.0 million, respectively. The unit sales were accounted for as equity transactions with no gain or loss recognized. The Company continued to be the primary beneficiary of the Royalty Trusts after consideration of these transactions and continues to consolidate the activities of the Royalty Trusts.

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 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 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.

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

PGC’s assets consist of approximately 370 miles ofgathering lines that support the Company’s production in the Piñon field in West Texas. The Company acquired PGC in October 2015, and upon acquisition, terminated a gas gathering and operations and maintenance agreement with PGC, which required the Company to compensate PGC for any throughput shortfalls below a required minimum volume through June 30, 2029. By guaranteeing a minimum throughput, the Company absorbed the risk that lower than projected volumes would be gathered by the PGC’s gathering system. Therefore, prior to its acquisition, PGC was a VIE. Other than as required under the gas gathering and operations and maintenance agreements, the Company did not provide any support to PGC. While the Company operated the assets of PGC as directed under the operations and management agreement, the member and managers of PGC had the authority to directly control PGC and make substantive decisions regarding PGC’s activities including terminating the Company as operator without cause. As the Company did not have the ability to control the activities of PGC that most significantly impact PGC’s economic performance, the Company was not the primary beneficiary of PGC and, therefore, and did not consolidate the results of PGC’s activities into the Company’s financial statements prior to its acquisition. As a wholly owned subsidiary, PGC is no longer considered a VIE for reporting purposes.

Amounts due from and due to PGC as of December 31, 2014 included in the accompanying consolidated balance sheet are as follows (in thousands):

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

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Fair Value Measurements

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

Level 1	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
Level 2	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3	Measurement based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).

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

Level 1 Fair Value Measurements

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

Level 2 Fair Value Measurements

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

Mandatory Prepayment Feature - PGC Senior Secured Notes. In conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015, the Company issued the PGC Senior Secured Notes with a $78.0 million principal value. These notes bear payment terms identical to and are secured by the same assets as the 8.75% Senior Secured Notes due 2020 issued by the Company in June 2015 as discussed in Note 12. The 8.75% Senior Secured Notes due 2020 issued in June 2015 and PGC Senior Secured Notes (collectively, “Senior Secured Notes”) will mature on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the Company’s unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019. The issuance of the PGC Senior Secured Notes at a substantial discount, as discussed in Note 12 and Note 13, resulted in the treatment of the mandatory prepayment feature contained in those notes as an embedded derivative that meets the criteria to be bifurcated from its host contract, the PGC Senior Secured Notes, and accounted for separately from those notes. The mandatory prepayment feature contained in the PGC Senior Secured Notes is recorded at fair value each reporting period based upon values determined through the use of discounted cash flow models of the PGC Senior Secured Notes both (i) with the mandatory prepayment feature and (ii) excluding the mandatory prepayment feature.

Level 3 Fair Value Measurements

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

Unobservable Input	Range							Weighted Average			Fair Value
	(Price per Mcf)										(In thousands)
December 31, 2015
Natural gas basis differential forward curve	$	(0.06	)	–	$	(0.28	)	$	(0.22	)	$	(1,748	)
December 31, 2014
Natural gas basis differential forward curve	$	(0.03	)	–	$	(0.38	)	$	(0.29	)	$	350

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

The fair values of the holder conversion features were determined using a binomial lattice model based on certain assumptions including (i) the Company’s stock price, (ii) risk-free rate, (iii) recovery rate, (iv) hazard rate and (v) expected volatility. The significant unobservable input used in the fair value measurement of the conversion features is the hazard rate, an estimate of default probability. Significant increases (decreases) in the hazard rate could result in significantly (lower) higher fair value measurement.The significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion features atDecember 31, 2015are included in the table below.

Unobservable Input	Range					Weighted Average		Fair Value
								(In thousands)
December 31, 2015
Long-term debt conversion feature hazard rate	114.0	%	–	135.2	%	119.2	%	$	29,355

See further discussion of the Convertible Senior Unsecured Notes at Note 12.

Guarantees. As discussed in Note 3, the Company guaranteed on Fieldwood’s behalf certain plugging and abandonment obligations associated with the Gulf Properties from the date of closing until the Company was released from the guarantee in the third quarter of 2015. The fair value of this guarantee was based on the present value of estimated future payments for plugging and abandonment obligations associated with the Gulf Properties, adjusted for the cumulative probability of Fieldwood’s default prior to the Company’s release by the BOEM from its obligation under the guarantee (3.71% at December 31, 2014). The discount and probability of default rates were based upon inputs that are readily available in the public market, such as historical option adjusted spreads of the Company’s senior notes, which are publicly traded, and historical default rates of publicly traded companies with credit ratings similar to Fieldwood. The significant unobservable input used in the fair value measurement of the guarantees was the estimate of future payments for plugging and abandonment of approximately $372.0 million, which was developed based upon third-party quotes and then-current actual costs. Significant increases (decreases) in the estimate of these payments could have resulted in a significantly higher (lower) fair value measurement.

Fair Value - Recurring Measurement Basis

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

December 31, 2015

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	85,524	$	—	$	(1,175	)	$	84,349
Investments	10,106		—		—		—			10,106
	$	10,106	$	85,524	$	—	$	(1,175	)	$	94,455
Liabilities
Commodity derivative contracts	$	—	$	—	$	1,748	$	(1,175	)	$	573
Long-term debt holder conversion feature	—		—		29,355		—			29,355
Mandatory prepayment feature - PGC Senior Secured Notes	—		2,941		—		—			2,941
	$	—	$	2,941	$	31,103	$	(1,175	)	$	32,869

December 31, 2014

	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	338,067	$	350	$	—	$	338,417
Investments	11,106		—		—		—		11,106
	$	11,106	$	338,067	$	350	$	—	$	349,523
Liabilities
Guarantee	$	—	$	—	$	5,104	$	—	$	5,104
	$	—	$	—	$	5,104	$	—	$	5,104

____________________

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

Level 3 - Commodity Derivative Contracts. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for commodity derivative contracts during the years ended December 31, 2015, 2014 and 2013 (in thousands):

Level 3 Fair Value Measurements - Commodity Derivative Contracts	2015			2014		2013
Beginning balance	$	350		$	—	$	(512	)
Loss on commodity derivative contracts	(350		)	—		(133		)
Purchases	(1,748		)	350		—
Settlements paid	—			—		645
Level 3 commodity derivative contracts at December 31	$	(1,748	)	$	350	$	—

Losses due to changes in fair value of the Company’s Level 3 commodity derivative contracts have been included in (gain) loss on derivative contracts in the accompanying consolidated statements of operations. There were no outstanding Level 3 commodity derivative contracts at December 31, 2013. See Note 13 for further discussion of the Company’s derivative contracts.

Level 3 - Long-Term Debt Holder Conversion Feature. The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for long-term debt holder conversion features during the year ended December 31, 2015 (in thousands):

Level 3 Fair Value Measurements - Long-Term Debt Holder Conversion Feature
Beginning balance	$	—
Issuances	31,200
Gain on derivative holder conversion feature	10,198
Conversions	(12,043		)
Ending balance	$	29,355

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

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

Level 3 Fair Value Measurements - Guarantee	2015			2014
Beginning balance	$	5,104		$	—
Issuances	—			9,446
Loss on guarantee	—			(4,342		)
Settlements	(5,104		)	—
Ending balance	$	—		$	5,104

While in effect, the fair value of the guarantee was determined quarterly with changes in fair value recorded as an adjustment to the full cost pool. See Note 3 for discussion of the sale of the Gulf Properties. The fair value of the guarantees as of December 31, 2014 is included in other current liabilities in the accompanying consolidated balance sheet.

Transfers. The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. During the years ended December 31, 2015, 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 - Long-Term Debt

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

	December 31, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
8.75% Senior Secured Notes due 2020(1)	$	403,098	$	1,301,098	$	—	$	—
Senior Unsecured Notes
8.75% Senior Notes due 2020(2)	$	39,740	$	392,666	$	303,750	$	445,402
7.5% Senior Notes due 2021(3)	$	79,812	$	759,711	$	752,000	$	1,178,486
8.125% Senior Notes due 2022	$	57,749	$	527,737	$	472,500	$	750,000
7.5% Senior Notes due 2023(4)	$	58,799	$	541,572	$	519,750	$	821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022(5)	$	44,199	$	82,294	$	—	$	—
7.5% Convertible Senior Notes due 2023(6)	$	15,125	$	26,428	$	—	$	—

___________________

(1) Carrying value includes mandatory prepayment feature liabilities with fair value of $2,941 and is net of $29,842 discount at December 31, 2015.

(2) Carrying value is net of $3,269 and $4,598 discount at December 31, 2015 and 2014, respectively.

(3) Carrying value includes a premium of $1,944 and $3,486 at December 31, 2015 and 2014, respectively.

(4) Carrying value is net of $1,989 and $3,452 discount at December 31, 2015 and 2014, respectively.

(5) Carrying value includes holder conversion feature liabilities with fair value of $21,874 and is net of $180,751 discount at December 31, 2015.

(6) Carrying value includes holder conversion feature liabilities with fair value of $7,481 and is net of $59,549 discount at December 31, 2015.

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Accounts Receivable

12 Months Ended

Dec. 31, 2015

Receivables [Abstract]

Accounts Receivable

Accounts Receivable

A summary of accounts receivable is as follows (in thousands):

	December 31,
	2015			2014
Oil, natural gas and NGL sales	$	61,140		$	139,848
Joint interest billing	60,403			170,937
Oil and natural gas services	2,417			21,436
Other	8,274			4,939
	132,234			337,160
Less: allowance for doubtful accounts	(4,847		)	(7,083		)
Total accounts receivable, net	$	127,387		$	330,077

The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2015			2014			2013
Beginning balance	$	7,083		$	11,061		$	5,635
Additions charged to costs and expenses(1)	1,320			818			5,497
Deductions(2)	(3,556		)	(4,796		)	(71		)
Ending balance	$	4,847		$	7,083		$	11,061

____________________

(1) Includes $2.7 million of allowance for receivables deemed uncollectible at December 31, 2013, primarily due to the bankruptcy status of customers.

(2) Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2015 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement, and deductions in 2014 are related to the sale of the Gulf Properties.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

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

	December 31,
	2015			2014
Oil and natural gas properties
Proved(1)	$	12,529,681		$	11,707,147
Unproved	363,149			290,596
Total oil and natural gas properties	12,892,830			11,997,743
Less accumulated depreciation, depletion and impairment	(11,149,888		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	1,742,942			5,638,594
Land	14,260			16,300
Non-oil and natural gas equipment(2)	373,687			602,392
Buildings and structures(3)	227,673			263,191
Total	615,620			881,883
Less accumulated depreciation and amortization	(123,860		)	(305,420		)
Other property, plant and equipment, net	491,760			576,463
Total property, plant and equipment, net	$	2,234,702		$	6,215,057

____________________

(1) Includes cumulative capitalized interest of approximately $48.9 million and $38.1 million at December 31, 2015 and 2014, respectively.

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

(3) Includes cumulative capitalized interest of approximately $20.4 million and $17.1 million at December 31, 2015 and 2014, respectively.

Accumulated depreciation, depletion and impairment for oil and natural gas properties includes cumulative full cost ceiling limitation impairment of $8.2 billion and $3.7 billion at December 31, 2015 and 2014, respectively. During the years ended December 31, 2015 and 2014, the Company reduced the net carrying value of its oil and natural gas properties by $4.5 billion and $164.8 million, respectively, as a result of its quarterly full cost ceiling analyses. There was no full cost ceiling impairment during the year ended December 31, 2013. See Note 8 for discussion of impairment of other property, plant and equipment.

The average rates used for depreciation and depletion of oil and natural gas properties were $10.67 per Boe in 2015, $15.00 per Boe in 2014 and $16.81 per Boe in 2013.

During the second and fourth quarters of 2015, the Company classified drilling and oilfield services assets having net book values of approximately $20.0 million and $16.0 million, respectively, as held for sale as a result of the Company’s decisions to discontinue substantially all drilling and oilfield services operations first in the Permian region and then companywide. The Company disposed of certain drilling and oilfield services assets held for sale during the third quarter of 2015 and recorded a loss on sale of assets of $3.5 million for the year ended December 31, 2015. The Company expects to dispose of the remaining assets classified as held for sale at December 31, 2015 prior to the fourth quarter of 2016.

Drilling Carry Commitments

During the years ended December 31, 2014 and 2013, the Company was party to 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 year ended December 31, 2014, and a combined $408.0 million for both Atinum MidCon I, LLC’s (“Atinum”) and Repsol’s drilling carries during the year ended December 31, 2013, which reduced the Company’s capital expenditures for the respective periods. Repsol fully funded its carry commitment in the third quarter of 2014, and the carry commitment from Atinum was fully utilized during the third quarter of 2013.

Under the original 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. Under the terms of the amended agreement, the Company agreed to carry Repsol’s future drilling and completion costs in the amount of $1.0 million for each well of the 484 commitment that it did not drill, up to a maximum of $75.0 million in carry costs.  As of May 31, 2015, the Company had drilled 453 net wells under this arrangement. As a result, the Company will carry a portion of Repsol’s drilling and completion costs totaling up to approximately $31.0 million for wells drilled in the future in the area of mutual interest. The Company incurred approximately $16.1 million in costs toward this obligation during the year ended December 31, 2015. Other than the above, the Company has no carry or drilling obligations to Repsol.

Costs Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2015 (in thousands):

			Year Cost Incurred
	Total		2015		2014		2013		2012 and Prior
Property acquisition	$	362,803	$	197,849	$	70,304	$	14,011	$	80,639
Exploration(1)	34,988		10,698		6,263		17,688		339
Total costs incurred	$	397,791	$	208,547	$	76,567	$	31,699	$	80,978

____________________

(1) Includes $34.7 million of pipe inventory costs incurred ($10.5 million in 2015, $6.2 million in 2014 and $18.0 million in 2013 and prior years).

The Company expects to complete the majority of the evaluation activities within 10 years from the applicable date of acquisition, contingent on the Company’s capital expenditures and drilling program. In addition, the Company’s internal engineers evaluate all properties on at least an annual basis.

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Impairment

12 Months Ended

Dec. 31, 2015

Asset Impairment Charges [Abstract]

Impairment

Impairment

Property, Plant and Equipment

As deemed necessary based on events in 2015, 2014 and 2013, the Company analyzed various property, plant and equipment for impairment. Estimated fair values of these assets were determined using a combination of the discounted cash flow method, recent offers from third-party purchasers or prices of comparable assets with consideration of current market conditions. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5.

Oil and Natural Gas Properties. The Company incurred impairments of $4.5 billion and $164.8 million for the years ended December 31, 2015 and 2014, respectively, due to a full cost ceiling limitations. The impairments recorded in 2015 resulted primarily from the significant decrease in oil prices, and to a lesser extent, natural gas prices, that began in the latter half of 2014 and continued in 2015. The impairment in 2014 resulted 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.

Drilling Assets. During 2015, the Company evaluated certain drilling assets for impairment based on the Company’s plans for their future use. As a result of these evaluations, the Company recorded impairments of $37.6 million for the year ended December 31, 2015. During the fourth quarter of 2015, the Company classified drilling and oilfield services assets having a net book value of approximately $16.0 million, as held for sale, which were included in other current assets in the accompanying consolidated balance sheet at December 31, 2015. See Note 7 for additional discussion of assets held for sale.

As a result of the Company’s fulfillment of its drilling obligation with the Permian Trust and the downward trend in oil prices that began in the second half of 2014, demand for the Company’s drilling and oilfield services in the Permian region declined significantly. At December 31, 2014, the Company determined the future use of its drilling and oilfield services assets in this region was limited and recorded an impairment of $24.3 million on these assets.

During 2014 and 2013, the Company committed to plans to sell various drilling assets. The net book value of these drilling assets was adjusted to fair value, resulting in impairments of $3.1 million and $11.1 million for the years ended December 31, 2014 and 2013, respectively. The remaining net book value of these assets is included in other current assets in the accompanying consolidated balance sheet at December 31, 2014.

Gas Treating Plants and Other Midstream Assets. During 2015, 2014 and 2013, the Company evaluated certain midstream pipe inventory, natural gas compressors, gas treating plants and a CO₂ compressor station for impairment when it was determined that their future use was limited. As a result of these evaluations, the Company recorded impairments of $7.1 million, $0.6 million and $12.2 million during the years ended December 31, 2015, 2014 and 2013, respectively, on these assets to reduce their carrying value to fair value.

Other Property, Plant and Equipment. In the fourth quarter of 2015, the Company signed an agreement to sell one of its properties located in downtown Oklahoma City, Oklahoma. Because the net book value of the property exceeded the agreed upon sales price, the Company adjusted the carrying value of the property to the agreed upon sales price, resulting in an impairment of $15.4 million for the year ended December 31, 2015. Additionally the company evaluated certain gathering and compression equipment for impairment when it was determined their future use was limited. As a result of these evaluations, the Company recorded an impairment of $0.7 million for the year ended December 31, 2015.

In the second quarter of 2013, the Company committed to a plan to sell a corporate asset. The net book value of the corporate asset was adjusted to fair value, resulting in an impairment of $2.9 million during the year ended December 31, 2013. The corporate asset was sold in the fourth quarter of 2013.

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Other Assets

12 Months Ended

Dec. 31, 2015

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Assets

Other Assets

Other assets consist of the following (in thousands):

	December 31,
	2015		2014
Debt issuance costs, net of amortization	$	72,259	$	56,445
Deferred tax asset(1)	—		95,843
Investments	10,106		11,106
Other	—		1,853
Total other assets	$	82,365	$	165,247

____________________

(1) The deferred tax asset at December 31, 2015, upon which there is a full valuation allowance, was netted against the deferred tax liability for presentation purposes as a result of the Company’s adoption of ASU 2015-17 in the fourth quarter of 2015. See Note 1.

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Accounts Payable and Accrued Expenses

12 Months Ended

Dec. 31, 2015

Payables and Accruals [Abstract]

Accounts Payable and Accrued Expenses

Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):

	December 31,
	2015		2014
Accounts payable and other accrued expenses	$	231,697	$	392,500
Accrued interest	73,320		79,704
Production payable	55,260		120,573
Payroll and benefits	42,728		44,496
Convertible perpetual preferred stock dividends	21,572		11,072
Drilling advances	2,295		33,195
Related party	1,545		1,852
Total accounts payable and accrued expenses	$	428,417	$	683,392

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Construction Contract

12 Months Ended

Dec. 31, 2015

Contractors [Abstract]

Construction Contract

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 consolidated statement of operations for the year ended December 31, 2013.

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Long-Term Debt

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

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

	December 31,
	2015		2014
Senior credit facility	$	—	$	—
8.75% Senior Secured Notes due 2020, including mandatory prepayment feature liabilities of $2,941, and net of $29,842 discount	1,301,098		—
Senior Unsecured Notes
8.75% Senior Notes due 2020, net of $3,269 and $4,598 discount, respectively	392,666		445,402
7.5% Senior Notes due 2021, including a premium of $1,944 and $3,486, respectively	759,711		1,178,486
8.125% Senior Notes due 2022	527,737		750,000
7.5% Senior Notes due 2023, net of $1,989 and $3,452 discount, respectively	541,572		821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount	82,294		—
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount	26,428		—
Total debt	3,631,506		3,195,436
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,631,506	$	3,195,436

See Note 22 for discussion of events occurring related to long-term debt subsequent to December 31, 2015.

Senior Credit Facility

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

The senior credit facility was amended and restated on June 10, 2015 (the “June Amendment”). In connection with the June Amendment, the then-existing financial covenants were replaced. As of then and as of December 31, 2015, the senior credit facility contains financial covenants, including maintenance of agreed upon levels for the (a) ratio of total secured debt under the senior credit facility to EBITDA, which may not exceed 2.00:1.00 at each quarter end and (b) ratio of current assets to current liabilities, which must be at least 1.0:1.0 at each quarter end. For the purpose of the current ratio calculation, any amounts available to be drawn under the senior credit facility are included in current assets, and unrealized assets and liabilities resulting from mark-to-market adjustments on the Company’s commodity derivative contracts are disregarded. The senior credit facility matures on the earlier of March 2, 2020 and 91 days prior to the earliest date of any maturity under or mandatory offer to repurchase the Company’s currently outstanding senior notes.

Prior and subsequent to the June Amendment, the senior credit facility also contains various covenants that limit the ability of the Company and certain of its subsidiaries to: grant certain liens; make certain loans and investments; make distributions; redeem stock; redeem or prepay debt; merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of the Company’s assets. On August 13, 2015, the senior credit facility was amended to allow the Company to redeem or purchase outstanding Senior Unsecured Notes for up to $200.0 million in cash subject to certain limitations and on October 16, 2015, concurrent with the October borrowing base redetermination, the senior credit facility was further amended to increase the amount of Senior Unsecured Notes the Company may redeem or purchase for cash to $275.0 million from $200.0 million. 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 year ended December 31, 2015, the Company was in compliance with all applicable financial covenants under the senior credit facility.

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

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

Borrowings and letter of credit obligations under the senior credit facility may not exceed the lower of the committed amount, which is currently $1.0 billion, or the borrowing base, which is $500.0 million and is subject to periodic redeterminations. Prior to the June Amendment, the borrowing base was $900.0 million. This reduction in borrowing base resulted in the write off of approximately $4.9 million of capitalized debt issuance costs. The borrowing base remained unchanged as a result of the October 2015 redetermination. The next scheduled borrowing base redetermination is expected to take place in April 2016; however, as discussed in Note 22, a special redetermination of the borrowing base was made in March 2016. With respect to each redetermination, the administrative agent and the lenders under the senior credit facility consider several factors, including the Company’s proved reserves and projected cash requirements, and make assumptions regarding, among other things, oil and natural gas prices and production. Because the value of the Company’s proved reserves is a key factor in determining the amount of the borrowing base, changing commodity prices and the Company’s success in developing reserves may affect the borrowing base. The Company at times incurs additional costs related to the senior credit facility as a result of amendments to the credit agreement and changes to the borrowing base.

The amended senior credit agreement permits the Company and certain of its subsidiaries to incur additional indebtedness in an aggregate principal amount not to exceed $1.75 billion, which may be secured solely by collateral securing the senior credit facility on a junior lien basis. Any junior lien debt shall be subject to the terms and conditions set forth in an intercreditor agreement and shall mature no earlier than January 21, 2020. The borrowing base under the senior credit facility will be reduced by $0.25 for every $1.00 of junior debt incurred above $1.50 billion.

The Company had no amounts outstanding under the senior credit facility at December 31, 2015 and $11.0 million in outstanding letters of credit, which reduce availability under the senior credit facility on a dollar-for-dollar basis. Additionally, at December 31, 2015, the Company had incurred $1.3 billion in junior lien debt subject to an intercreditor agreement as a result of the issuance of Senior Secured Notes in June 2015 and the PGC Senior Secured Notes in October 2015 as described further below.

Senior Secured Notes

Concurrent with the amendment and restatement of the Company’s senior credit facility discussed above, in June 2015 the Company issued $1.25 billion of 8.75% Senior Secured Notes due 2020. Net proceeds from the issuance were approximately $1.21 billion after deducting offering expenses, a portion of which was used to repay amounts outstanding at that time under the Company’s senior credit facility. The Senior Secured Notes were issued to qualified institutional buyers eligible under Rule 144A of the Securities Act and to persons outside the United States under Regulation S of the Securities Act.

Additionally, the Company issued the PGC Senior Secured Notes in conjunction with the acquisition of and termination of a gathering agreement with PGC in October 2015. Because the PGC Senior Secured Notes were issued as partial consideration for the acquisition and termination, these notes were recorded at fair value of approximately $50.3 million ($78.0 million par value, including mandatory prepayment feature liabilities of $2.8 million, net of $30.5 million discount) upon their issuance. Fair value at issuance was determined based upon the then-current market value of the Senior Secured Notes. The PGC Senior Secured Notes were issued at a discount that is being amortized to interest expense over the term of the Senior Secured Notes.

The Company’s Senior Secured Notes bear interest at a fixed rate of 8.75% per annum, payable semi-annually, with the principal due upon maturity. The Senior Secured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on a second-priority secured basis by certain of the Company’s wholly owned subsidiaries.

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

Debt issuance costs of $39.2 million incurred in connection with the offering of the Senior Secured Notes outstanding at December 31, 2015 are included in other assets in the accompanying unaudited condensed consolidated balance sheet and are being amortized to interest expense over the term of Senior Secured Notes.

Maturity Date and Mandatory Prepayment Feature. Pursuant to the indenture, the Senior Secured Notes will mature on June 1, 2020; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019. See further discussion of the mandatory prepayment feature, which with respect to the PGC Senior Secured Notes is an embedded derivative that has been accounted for separately from these notes, at Note 5 and Note 13.

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

Senior Unsecured Notes

The Company’s Senior Unsecured Notes bear interest at a fixed rate per annum, payable semi-annually, with the principal due upon maturity. Certain of the Senior Unsecured Notes were issued at a discount or a premium. The discount or premium is amortized to interest expense over the term of the respective series of Senior Unsecured Notes. The Senior Unsecured Notes are redeemable, in whole or in part, prior to their maturity at specified redemption prices and are jointly and severally guaranteed unconditionally, in full, on an unsecured basis by certain of the Company’s wholly owned subsidiaries. See Note 24 for condensed financial information of the subsidiary guarantors.

Debt issuance costs of $48.9 million incurred in connection with the offerings and subsequent registered exchange offers of the Senior Unsecured Notes outstanding, including the impact of write offs in conjunction with the repurchases and exchanges discussed below, are included in other assets in the accompanying consolidated balance sheet at December 31, 2015 and are being amortized to interest expense over the term of the respective series of Senior Unsecured Notes.

Indentures. Each of the indentures governing the Company’s Senior Unsecured Notes contains covenants that restrict the Company’s ability to take a variety of actions, including limitations on the incurrence of indebtedness, payment of dividends, investments, asset sales, certain asset purchases, transactions with related parties and consolidations or mergers. As of and during the year ended December 31, 2015, the Company was in compliance with all of the covenants contained in the indentures governing its outstanding Senior Notes.

2015 Activity

Redemption of Senior Unsecured Notes. During the second quarter of 2015, the Company issued to a holder of its 7.5% Senior Notes due 2021 and 8.125% Senior Notes due 2022, approximately 28.0 million shares of the Company’s common stock in exchange for an aggregate $50.0 million principal amount of the notes ($29.0 million of 7.5% Senior Notes due 2021 and $21.0 million of 8.125% Senior Notes due 2022) and as payment for the interest accrued thereon since the last interest payment date. The exchange resulted in a gain on extinguishment of $17.9 million, which is included in other income on the accompanying consolidated statement of operations for the year ended December 31, 2015.

Repurchase and Exchange of Senior Unsecured Notes. In August 2015, the Company repurchased $250.0 million of its Senior Unsecured Notes comprised of (i) $29.3 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $111.6 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $26.1 million aggregate principal amount of its 8.125% Senior Notes due 2022 and (iv) $83.0 million aggregate principal amount of its 7.5% Senior Notes due 2023, for approximately $94.5 million cash. The repurchase resulted in a gain on extinguishment of $152.0 million, including the write off of $3.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for the year ended December 31, 2015. In conjunction with the repurchase, the Company also exchanged $275.0 million of its Senior Unsecured Notes for newly-issued Convertible Senior Unsecured Notes, as discussed further below.

In October 2015, the Company repurchased $100.0 million of its Senior Unsecured Notes comprised of (i) $2.2 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $46.6 million aggregate principal amount of its 7.5% Senior Notes due 2021, and (iii) $51.2 million aggregate principal amount of its 7.5% Senior Notes due 2023, for approximately $30.0 million in cash. The repurchase resulted in a gain on extinguishment of $68.7 million, including the write off of $1.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for the year ended December 31, 2015. In conjunction with the repurchase, the Company also exchanged approximately $300.0 million of its Senior Unsecured Notes for newly-issued Convertible Senior Unsecured Notes, as discussed further below.

2013 Activity

In March 2013, the Company redeemed $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 consolidated statement of operations for the year ended December 31, 2013.

Convertible Senior Unsecured Notes

In conjunction with the repurchase of Senior Unsecured Notes in August 2015, the Company also exchanged $275.0 million of its Senior Unsecured Notes, comprised of (i) $15.9 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $40.7 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $101.8 million aggregate principal amounts of its 8.125% Senior Notes due 2022 and (iv) $116.6 million aggregate principal amount of its 7.5% Senior Notes due 2023, for (i) $158.4 million aggregate principal amount of newly-issued 8.125% Convertible Senior Notes due 2022 and (ii) $116.6 million aggregate principal amount of newly-issued 7.5% Convertible Senior Notes due 2023. The exchange resulted in a gain on extinguishment of $189.0 million, including the write off of $4.0 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations year ended December 31, 2015.

In conjunction with the repurchase of Senior Unsecured Notes in October 2015, the Company exchanged $300.0 million of its Senior Unsecured Notes, comprised of (i) $6.6 million aggregate principal amount of its 8.75% Senior Notes due 2020, (ii) $189.3 million aggregate principal amount of its 7.5% Senior Notes due 2021, (iii) $73.5 million aggregate principal amounts of its 8.125% Senior Notes due 2022 and (iv) $30.6 million aggregate principal amount of its 7.5% Senior Notes due 2023, for (i) $269.4 million aggregate principal amount of newly-issued 8.125% Convertible Senior Notes due 2022 and (ii) $30.6 million aggregate principal amount of newly-issued 7.5% Convertible Senior Notes due 2023. The exchange resulted in a gain on extinguishment of $207.4 million, including the write off of $4.0 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations year ended December 31, 2015.

The Convertible Senior Unsecured Notes are guaranteed by the same guarantors that guarantee the Senior Unsecured Notes and are subject to covenants and bear payment terms substantially identical to those of the corresponding series of Senior Unsecured Notes of similar tenor, other than the conversion features, described further below, and the extension of the final maturity by one day. The transactions were determined to be an extinguishment of each of the Senior Unsecured Notes exchanged. As such, the newly-issued Convertible Senior Unsecured Notes were recorded at fair value on the date of issuance, which resulted in a discount that is being amortized to interest expense over the term of the respective series of Convertible Senior Unsecured Notes.

Debt issuance costs of $6.3 million incurred in connection with the issuance of the Convertible Senior Unsecured Notes, including the impact of write offs in conjunction with the conversions discussed below, are included in other assets in the accompanying consolidated balance sheet at December 31, 2015 and are being amortized to interest expense over the term of the respective series of Convertible Senior Unsecured Notes.

Conversion Features. The Convertible Senior Unsecured Notes are convertible, at the option of the holders, into shares of common stock at any time prior to (i) the fifth business day following the date of a mandatory conversion notice, discussed further below, (ii) with respect to Convertible Senior Unsecured Notes called for redemption, the business day immediately preceding the redemption date or (iii) the business day immediately preceding the maturity date. The conversion rate isapproximately 363.6 shares of common stock per $1,000 principal amount of the Convertible Senior Unsecured Notes, subject to customary adjustments. With respect to any conversions prior to the first anniversary of the issuance of the Convertible Senior Unsecured notes, in addition to the shares deliverable upon conversion, holders are entitled to receive an early conversion payment equal to the amount of 18 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. With respect to any conversion subsequent to the first anniversary of the issuance of the Convertible Senior Unsecured Notes, but on or prior to the second anniversary of the issuance of such Convertible Senior Unsecured Notes, holders are entitled to receive an early conversion payment equal to the amount of 12 months of interest payable on the applicable series of converted Convertible Senior Unsecured Notes. The dilutive effect, if any, of the Convertible Senior Unsecured Notes on the Company’s earnings per share is determined using the if-converted method. See further discussion at Note 20.

See further discussion of the holders’ conversion features, which are embedded derivatives that have been accounted for separately from the Convertible Senior Unsecured Notes, at Note 5 and Note 13.

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

Conversions to Common Stock. During the year ended December 31, 2015, holders of $186.6 million aggregate principal amount ($54.4 million net of discount and including holders’ conversion feature) of 8.125% Convertible Senior Notes due 2022 and $68.7 million aggregate principal amount ($19.3 million net of discount and holders’ conversion feature) of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 92.8 million shares of Company common stock and aggregate cash payments of $30.5 million for accrued interest and early conversion payments. The conversions resulted in a gain on extinguishment of debt totaling $6.1 million, including the write off of $5.2 million of net unamortized debt issuance costs, which is included in other income on the accompanying consolidated statement of operations for year ended December 31, 2015.

Maturities of Long-Term Debt

As of December 31, 2015, $1.7 billion of long-term debt will mature in 2020, with the remainder of long-term debt maturing thereafter; provided, however, that if on October 15, 2019, the aggregate outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million, the Senior Secured Notes will mature on October 16, 2019.

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Derivatives

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

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.

Commodity Derivatives

The Company is exposed to commodity price risk, which impacts the predictability of its cash flows from the sale of oil and natural gas. The Company seeks to manage this risk through the use of commodity derivative contracts, which allow the Company to limit its exposure to commodity price volatility on a portion of its forecasted oil and natural gas sales. None of the Company’s commodity derivative contracts may be terminated prior to contractual maturity solely as a result of a downgrade in the credit rating of a party to the contract. Cash settlements and valuation gains and losses on commodity derivative contracts are included in (gain) loss on derivative contracts in the consolidated statements of operations. Commodity derivative contracts are settled on a monthly or quarterly basis. Derivative assets and liabilities arising from the Company’s commodity derivative contracts with the same counterparty that provide for net settlement are reported on a net basis in the consolidated balance sheets. At December 31, 2015, 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.
Basis swaps	The Company receives a payment from the counterparty if the settled price differential is greater than the stated terms of the contract and pays the counterparty if the settled price differential is less than the stated terms of the contract, which guarantees the Company a price differential for oil or natural gas from a specified delivery point.
Collars	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 plus the difference between the purchased put and the sold put strike price. The call establishes a maximum price (ceiling) the Company will receive for the volumes under the contract.

The Company recorded (gain) loss on commodity derivative contracts of $(73.1) million, $(334.0) million and $47.1 million for the years ended December 31, 2015, 2014 and 2013, respectively, as reflected in the accompanying consolidated statements of operations, which includes net cash (receipts) payments upon settlement of $(327.7) million, $32.3 million and $(0.8) million, respectively. Included in these net cash (receipts) payments are $69.6 million and $29.6 million of cash payments related to settlements of commodity derivative contracts with contractual maturities after the year in which they were settled primarily as a result of the sale of the Gulf Properties in February 2014 and the Permian Properties in February 2013, respectively.

Derivatives Agreements with Royalty Trusts. During the years ended December 31, 2015, 2014 and 2013, the Company was party to derivatives agreements with the Mississippian Trust I, Permian Trust and Mississippian Trust II to provide each Royalty Trust with the economic effect of certain oil and natural gas derivative contracts entered into by the Company with third parties. The derivatives agreements with the Mississippian Trust I and the Mississippian Trust II contained commodity derivative contracts that covered volumes of oil and natural gas production through December 31, 2015, and the derivatives agreement with the Permian Trust contained commodity derivative contracts that covered volumes of oil production through March 31, 2015. In accordance with the terms of the respective derivatives agreements, the Company novated certain of the commodity derivative contracts underlying the derivatives agreements to each of the Permian Trust and the Mississippian Trust II. As a party to these contracts, the Permian Trust and Mississippian Trust II received payment directly from the counterparty and paid any amounts owed directly to the counterparty during the terms of these novated contracts. 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. The derivatives agreements expired upon expiration of the associated underlying derivative contracts and were no longer in effect as of December 31, 2015. All activity related to the contracts underlying the derivatives agreements with the Royalty Trusts have been included in the Company’s consolidated derivative disclosures.

Master Netting Agreements and the Right of Offset. The Company has master netting agreements with all of its commodity derivative counterparties and has presented its derivative assets and liabilities with the same counterparty on a net basis in the consolidated balance sheets. As a result of the netting provisions, the Company's maximum amount of loss under commodity derivative transactions due to credit risk is limited to the net amounts due from its counterparties. As of December 31, 2015, the counterparties to the Company’s open commodity derivative contracts consisted of eight financial institutions, three of which are also lenders under the Company’s senior credit facility. The Company is not required to post additional collateral under its commodity derivative contracts as certain of the counterparties to the Company’s commodity derivative contracts share in the collateral supporting the Company’s senior credit facility. To secure their obligations under the commodity derivative contracts novated by the Company, the Permian Trust and the Mississippian Trust II gave the counterparties to such contracts a lien on their respective royalty interests. As of December 31, 2015, the terms of all such novated contracts had expired. The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the senior credit facility (in thousands):

December 31, 2015

	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Liabilities
Derivative contracts - current	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—

December 31,2014

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

At December 31, 2015, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2016 - December 2016	1,464	$	88.36

Natural Gas Basis Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way

	Notional (MBbls)	Sold Put		Purchased Put		Sold Call
January 2016 - December 2016	2,556	$	83.14	$	90.00	$	100.85

Long-Term Debt - Embedded Derivatives

Long-Term Debt Holder Conversion Feature. As discussed further in Note 5 and Note 12, the Convertible Senior Unsecured Notes contain a conversion feature that is exercisable at the holders’ option. This conversion feature has been identified as an embedded derivative as the feature (i) possesses economic characteristics that are not clearly and closely related to the economic characteristics of the host contract, the Convertible Senior Unsecured Notes, and (ii) separate, stand-alone instruments with the same terms would qualify as derivative instruments. As such, the holders’ conversion feature has been bifurcated and accounted for separately from the Convertible Senior Unsecured Notes. The holders’ conversion feature is recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statement of operations for the year ended December 31, 2015.

Mandatory Prepayment Feature - PGC Senior Secured Notes. As discussed further in Note 5 and Note 12, the Senior Secured Notes contain a mandatory prepayment feature that is triggered if the outstanding principal amount of the unsecured 8.75% Senior Notes due 2020 exceeds $100.0 million on October 15, 2019. With respect to the PGC Senior Secured Notes, which were issued at a substantial discount, this mandatory prepayment feature has been identified as an embedded derivative as the feature (i) possesses economic characteristics that are not clearly and closely related to the economic characteristics of the host contract, the PGC Senior Secured Notes, and (ii) separate, stand-alone instruments with the same terms would qualify as derivative instruments. As such, the mandatory prepayment feature contained in the PGC Senior Secured Notes has been bifurcated and accounted for separately from those notes. The mandatory prepayment feature contained in the PGC Senior Secured notes is recorded at fair value each reporting period with changes in fair value included in interest expense in the accompanying consolidated statement of operations for the year ended December 31, 2015.

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 its outstanding 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 swaps of $0.01 million for the year ended December 31, 2013, which is included in interest expense in the accompanying consolidated statement of operations. Included in the loss for the year ended December 31, 2013 are cash payments upon contract settlement of $2.4 million.

Fair Value of Derivatives

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

		December 31,
Type of Contract	Balance Sheet Classification	2015			2014
Derivative assets
Oil price swaps	Derivative contracts—current	$	68,224		$	204,072
Natural gas price swaps	Derivative contracts—current	—			29,648
Natural gas basis swaps	Derivative contracts—current	—			350
Oil collars—three way	Derivative contracts—current	17,300			56,289
Natural gas collars	Derivative contracts—current	—			1,055
Oil price swaps	Derivative contracts—noncurrent	—			36,288
Oil collars—three way	Derivative contracts—noncurrent	—			10,715
Derivative liabilities
Natural gas basis swaps	Derivative contracts—current	(1,748		)	—
Long-term debt holder conversion feature	Long-term debt	(29,355		)	—
Mandatory prepayment feature - PGC Senior Secured Notes	Long-term debt	(2,941		)	—
Total net derivative contracts		$	51,480		$	338,417

See Note 5 for additional discussion of the fair value measurement of the Company’s derivative contracts and Note 12 for discussion of the long-term debt holder conversion and mandatory prepayment features.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The following table presents the balance and activity of the asset retirement obligations for the years ended December 31, 2015, 2014 and 2013 (in thousands).

	2015			2014			2013
Beginning balance	$	54,402		$	424,117		$	498,410
Liability incurred upon acquiring and drilling wells	1,662			4,968			5,078
Revisions in estimated cash flows(1)	44,060			(5,848		)	(3,077		)
Liability settled or disposed in current period(2)	(1,023		)	(377,927		)	(113,071		)
Accretion	4,477			9,092			36,777
Ending balance	103,578			54,402			424,117
Less: current portion	8,399			—			87,063
Asset retirement obligations, net of current	$	95,179		$	54,402		$	337,054

____________________

(1) Revisions for the year ended December 31, 2015 relate primarily to changes in estimated well lives.

(2) Liability settled or disposed for the year ended December 31, 2014, includes $366.0 million associated with the Gulf Properties sold in February 2014, as discussed in Note 3.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Operating Leases. The Company has obligations under noncancelable operating leases, primarily for office space and equipment used in drilling and services activities. Total rental expense under operating leases for the years ended December 31, 2015, 2014 and 2013 was approximately $1.0 million, $1.7 million and $3.6 million, respectively.

Future minimum payments under noncancelable operating leases (with initial lease terms exceeding one year) as of December 31, 2015 were as follows (in thousands):

Years ending December 31
2016	$	584
2017	555
2018	485
2019	72
2020	—
Thereafter	—
	$	1,696

Rig Commitments. The Company has contracts with third-party drilling rig operators for the use of their rigs at specified day or footage rates. These commitments are not recorded in the consolidated balance sheets. The minimum future commitment for 2016 was $2.5 million as of December 31, 2015, with no such commitments subsequent to 2016.

Oil and Natural Gas Transportation and Throughput Agreements. The Company has subscribed firm gas transportation service under a transportation service agreement on the Midcontinent Express Pipeline, the term of which continues until July 2019. This commitment is not recorded in the consolidated balance sheets. Under the terms of the agreement, the Company is obligated to pay a demand charge and in exchange, obtains the right to flow natural gas production through this pipeline to more competitive marketing areas. The Company also has oil and natural gas throughput agreements in place, which require fixed fees based on minimum volume requirements for the right to flow oil and natural gas through certain pipelines. The amounts of the required payments related to the transportation and throughput agreements as of December 31, 2015 were as follows (in thousands):

Years ending December 31
2016	$	14,082
2017	13,869
2018	14,163
2019	9,282
2020	1,584
Thereafter	11,088
	$	64,068

Treating Agreement. At December 31, 2015, the Company was party to a 30-year treating agreement with Occidental Petroleum Corporation (“Occidental”) for the removal of CO₂ from natural gas volumes delivered by the Company. Under the agreement, the Company was required to deliver a total of approximately 3,200 Bcf of CO₂ during the agreement period. The Company was obligated to pay Occidental $0.25 per Mcf to the extent minimum annual CO₂ volume requirements were not met. Through December 31, 2015, the Company had delivered to Occidental 73.1 Bcf of CO_2, which is 439.6 Bcf less than the cumulative minimum annual CO₂ volume requirements for the same period and had accrued associated annual shortfall penalties of approximately $109.9 million. As discussed in Note 22, the Company was released from all past, current and future obligations related to this agreement in January 2016.

Risks and Uncertainties. The Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for oil and natural gas, which depend on numerous factors beyond the Company’s control such as overall oil and natural gas production and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations in the future. The Company enters into commodity derivative arrangements from time to time, depending upon management’s view of opportunities under the then-prevailing current market conditions, in order to mitigate a portion of the effect of this price volatility on the Company’s cash flows. See Note 13 for the Company’s open oil and natural gas commodity derivative contracts.

Production targets contained in certain gathering and treating agreements require the Company to incur capital expenditures or make associated shortfall payments, as discussed above. The Company depends on cash flows from operating activities and, as necessary, borrowings under its senior credit facility to fund its capital expenditures. Based on current cash balances, cash flows from operating activities and net borrowings under the senior credit facility in 2016, the Company expects to be able to fund its planned capital expenditures budget, debt service requirements and working capital needs for 2016; however, if current depressed oil or natural gas prices persist for a prolonged period or further decline, they would have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced, which would adversely impact the Company’s ability to comply with the financial covenants under its senior credit facility. See Note 12 for discussion of the financial covenants in the senior credit facility and Note 22 for discussion of events occurring related to the senior credit facility subsequent to December 31, 2015.

On January 7, 2016, the Company’s stock was delisted from trading on the New York Stock Exchange as a result of having traded below certain required thresholds. Such delisting could impact the Company’s ability to generate funds from equity financing.

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

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

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

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

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

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

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

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

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

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

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

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

On September 26, 2014, the Board 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.

On October 7, 2015, the derivative plaintiffs in the Federal Shareholder Derivative Litigation, the SLC, and the individual defendants in the Federal Shareholder Derivative Litigation (Tom Ward, Jim Brewer, Everett Dobson, William Gilliland, Daniel Jordan, Roy Oliver Jr., and Jeffrey Serota), executed a Stipulation of Settlement, which would result in a partial settlement of the Federal Shareholder Derivative Litigation by settling all claims against the individual defendants, subject to certain terms and conditions, including the approval of the court. Under the terms of the proposed partial settlement, the Company would implement or agree to maintain certain corporate governance reforms, and the insurers for the individual defendants would pay $38.0 million to an escrow fund, which would be used to pay certain expenses arising from pending securities litigation and, to the extent funds remain after paying such expenses, would be paid to the Company without any further restrictions on the Company’s use of such funds. The proposed partial settlement expressly provides, among other terms, that the settling defendants deny all allegations of wrongdoing and are entering into the settlement solely to avoid the costs, disruption, uncertainty, and risk of further litigation.

On October 9, 2015, the court issued an Order granting preliminary approval of the Stipulation of Settlement and, after notice and a hearing on December 18, 2015, the court issued a Final Judgment and Order on December 22, 2015, granting final approval of the Stipulation of Settlement. The partial settlement did not settle any of the derivative plaintiffs’ claims against non-settling defendants WCT Resources, L.L.C., 192 Investments, L.L.C., and TLW Land & Cattle, L.P in the Federal Shareholder Derivative Litigation. On January 12, 2016, a shareholder who objected to the Stipulation of Settlement filed a notice of appeal of the court’s Final Judgment and Order approving the Stipulation of Settlement.

On November 30, 2015, the court stayed the Hefner action until further order of the court. An estimate of reasonably possible losses associated with the Hefner action cannot be made at this time. The Company has not established any reserves relating to this action.

On December 5, 2012, James Glitz and Rodger A. Thornberry, on behalf of themselves and all other similarly situated stockholders, filed a putative class action complaint in the U.S. District Court for the Western District of Oklahoma against the Company and certain current and former executive officers of the Company. On January 4, 2013, Louis Carbone, on behalf of himself and all other similarly situated stockholders, filed a substantially similar putative class action complaint in the same court and against the same defendants. On March 6, 2013, the court consolidated these two actions under the caption “In re SandRidge Energy, Inc. Securities Litigation” (the “Securities Litigation”) and appointed a lead plaintiff and lead counsel. On July 23, 2013, plaintiffs filed a consolidated amended complaint, which asserts a variety of federal securities claims against the Company and certain of its current and former officers and directors, among other defendants, on behalf of a putative class of (a) purchasers of SandRidge common stock during the period from February 24, 2011 to November 8, 2012, (b) purchasers of common units of the Mississippian Trust I in or traceable to its initial public offering on or about April 12, 2011, and (c) purchasers of common units of the Mississippian Trust II (together with the Mississippian Trust I, the “Mississippian Trusts”) in or traceable to its initial public offering on or about April 23, 2012. The claims are based on allegations that the Company, certain of its current and former officers and directors, and the Mississippian Trusts, among other defendants, are responsible for making false and misleading statements, and omitting material information, concerning a variety of subjects, including oil and natural gas reserves, the Company's capital expenditures, and certain transactions entered into by companies allegedly affiliated with the Company's former CEO Tom Ward.

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

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

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

On July 15, 2013, James Hart and 15 other named plaintiffs filed an Amended Complaint in the United States District Court for the District of Kansas in an action undertaken individually and on behalf of others similarly situated against SandRidge Energy, Inc., SandRidge Operating Company, SandRidge 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 Class and a Motion to Toll the Statute of Limitations. On October 11, 2013, the defendants filed a Motion to Dismiss and a Motion to Transfer Venue to the United States District Court for the Western District of Oklahoma.

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

On May 27, 2015, the parties reached an agreement in principle to settle this lawsuit. Pursuant to such agreement, the Company will establish a settlement fund from which to pay participating plaintiffs’ claims as well as plaintiffs’ attorneys’ fees. The proposed settlement agreement is subject to final negotiations between the parties and court approval. During the year ended December 31, 2015, the Company established a $5.1 million reserve for this lawsuit.

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

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

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

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

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

On November 24, 2015, the plaintiffs filed a Consolidated Class Action Complaint in the consolidated Gernandt action. The Company intends to defend this consolidated lawsuit vigorously. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Company has not established any reserves relating to this action.

On November 18, 2015, Mickey Peck, on behalf of himself and others similarly situated, filed a First Amended Collective Action Complaint in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc., and SandRidge Operating Company for violations of the Fair Labor Standards Act. Plaintiff alleges that the Company improperly classified certain of its consultants as independent contractors rather than as employees and, therefore, improperly paid such consultants a day rate without paying any overtime compensation. On January 14, 2016, the Court entered an Order conditionally certifying the class and providing for notice. 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 January 12, 2016, Lisa Griggs and April Marler, on behalf of themselves and all other similarly situated, filed a putative class action petition in the District Court of Logan County, Oklahoma, against SandRidge Exploration and Production, LLC, and certain other oil and gas exploration companies. In their petition, plaintiffs assert various tort claims based upon purported damage and loss resulting from earthquakes allegedly caused by the defendants’ operations of wastewater disposal wells. Plaintiffs seek to certify a class of “all residents of Oklahoma owning real property from 2011 through the time the Class is certified.” On February 16, 2016, the defendants filed a Notice of Removal of the lawsuit to the United States District Court for the Western District of Oklahoma. 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 February 12, 2016, Brenda Lene and Jon Darryn Lene filed a petition in the District Court of Logan County, Oklahoma, against SandRidge Exploration and Production, LLC, and certain other oil and gas exploration companies. In their petition, plaintiffs assert various tort claims based on their allegations that their home suffered damages due to earthquakes allegedly caused by the defendants’ operations of wastewater disposal wells. 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 March 3, 2016, Brian Thieme, on behalf of himself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that, commencing on or around December 27, 2007, and continuing until at least March 31, 2012, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties containing producing oil and natural gas wells located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Sections 1 and 3 of the Sherman Antitrust Act. Plaintiff seeks to certify two separate and distinct classes of members. 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 March 10, 2016, Don Beadles, in Trust for the Alva Synagogue Church, on behalf of himself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that since as early as December 2007, and continuing until at least as late as March 2012 (the “Relevant Class Period”), the defendants conspired to rig bids and otherwise depress the amounts they paid to property owners for the acquisition of oil and gas leasehold interests and producing properties located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Sections 1 and 3 of the Sherman Antitrust Act. Plaintiff seeks to certify a class of “all persons and entities that, during the Relevant Class Period, provided or sold to one of more of the Defendants (a) oil and gas leasehold interests on their property and/or (b) the producing properties, in exchange for lease payments, including but not limited to lease bonuses.” 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 March 24, 2016, Janet L. Lowry, on behalf of herself and all others similarly situated, filed a putative class action petition in the United States District Court for the Western District of Oklahoma against SandRidge Energy, Inc. and the Company’s former CEO, Tom L. Ward, among other defendants. Plaintiff alleges that, commencing on or around December 27, 2007, and continuing until at least March 31, 2012, the defendants conspired to rig bids and depress the price of royalty and bonus payments exchanged for purchases of oil and natural gas leasehold interests and interests in properties containing producing oil and natural gas wells located in certain areas of Oklahoma, Texas, Colorado and Kansas, in violation of Section 1 of the Sherman Antitrust Act. Plaintiff seeks to certify two separate and distinct classes of members. 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 February 4, 2015, the staff of the SEC Enforcement Division in Washington, D.C., notified the Company that it had commenced an informal inquiry concerning the Company’s accounting for, and disclosure of, its carbon dioxide delivery shortfall penalties under the terms of the Gas Treating and CO2 Delivery Agreement, dated June 29, 2008, between SandRidge Exploration and Production, LLC, and Oxy USA Inc.

Additionally, the Company received a letter from an attorney for a former employee at the Company (the “Former Employee”). In the letter, the attorney alleged, among other things, that the Former Employee had been terminated because he had objected to the levels of oil and gas reserves disclosed by the Company in its public filings. Over 85% of such reserves were calculated by an independent petroleum engineering firm.  The Audit Committee of the Company’s Board of Directors has retained an independent law firm to review the Former Employee’s allegations and the circumstances of the Former Employee’s termination.  In addition, the Company reported the Former Employee’s allegations to the SEC staff, which thereafter issued two subpoenas to the Company relating to the Former Employee’s allegations.  Counsel for the Audit Committee is responding to both of these subpoenas.

During the course of the above inquiries, the SEC issued a subpoena to the Company seeking documents relating to employment-related agreements between the Company and certain employees. The Company is cooperating with this inquiry and, after discussion with the staff, the Company sent corrective letters to certain current and former employees who had entered into agreements containing language that may have been inconsistent with SEC rules prohibiting a company from impeding an individual from communicating directly with the SEC about possible securities law violations. The Company also updated its Code of Conduct and other relevant policies.

The Company continues to cooperate with the above inquiries and is unable to predict their outcome or the possible loss, if any, that could result from their potential resolution.

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.

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Equity

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Equity

Equity

Preferred Stock

The following table presents information regarding the Company’s preferred stock (in thousands):

	December 31,
	2015	2014
Shares authorized, $0.001 par value	50,000	50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock	2,650	2,650
7.0% Convertible perpetual preferred stock(1)	2,770	3,000

____________________

(1) For the year ended December 31, 2015, approximately 230,500 shares were converted into approximately 3.0 million shares of the Company’s common stock.

All of the outstanding shares of the Company’s convertible perpetual preferred stock were issued in private transactions, but are now freely tradable, to the extent not owned by affiliates. In December 2014, all shares of the Company’s outstanding 6.0% convertible preferred stock converted automatically into shares of the Company’s common stock at the then-prevailing conversion rate, resulting in the issuance of approximately 18.4 million shares of common stock.

Each outstanding share of convertible perpetual preferred stock is convertible at the holder’s option at any time into shares of the Company’s common stock at the specified conversion rate, subject to customary adjustments in certain circumstances. Each holder is entitled to an annual dividend payable semi-annually in cash, common stock or a combination thereof, at the Company’s election. The Company may cause all outstanding shares of the convertible perpetual preferred stock to convert automatically into common stock at the prevailing conversion rate dependent on certain factors, including the Company’s stock trading above specified prices for a set period. The convertible perpetual preferred stock is not redeemable by the Company at any time. The following table summarizes information about each series of the Company’s convertible perpetual preferred stock outstanding at December 31, 2015:

	Convertible Perpetual Preferred Stock
	8.5%		7.0%
Liquidation preference per share	$	100.00	$	100.00
Annual dividend per share	$	8.50	$	7.00
Conversion rate per share to common stock	12.4805		12.8791

Preferred Stock Dividends. In accordance with the terms governing the Company’s convertible perpetual preferred stock, dividends may be paid in cash or with shares of the Company’s common stock at the Company’s election. Preferred stock dividend payments and accruals for the Company’s 8.5%, 7.0% and 6.0% convertible perpetual preferred stock for the years ended December 31, 2015, 2014 and 2013 are as follows:

	December 31,
	2015		2014		2013
	(In thousands)
8.5% Convertible perpetual preferred stock
Dividends paid in cash	$	11,262	$	22,525	$	22,525
Dividends satisfied in shares of common stock(1)	$	11,262	$	—	$	—
Accrued dividends at period end	$	8,447	$	8,447	$	8,447
7.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	21,000	$	21,000
Dividends satisfied in shares of common stock(2)	$	10,500	$	—	$	—
Accrued dividends at period end	$	13,125	$	2,625	$	2,625
Dividends in arrears(3)	$	10,500	$	—	$	—
6.0% Convertible perpetual preferred stock(4)
Dividends paid in cash	$	—	$	12,000	$	12,000
Accrued dividends at period end	$	—	$	—	$	5,500

____________________

(1) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 18.6 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, ($3.58 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying condensed consolidated statement of operations.

(2) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 5.7 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, ($2.23 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying condensed consolidated statement of operations.

(3) In the third quarter of 2015, the Company announced the suspension of payment of the semi-annual dividend on shares of its 7.0% convertible perpetual preferred stock.

(4) The final dividend payment for the 6.0% convertible preferred stock was made during 2014.

Paid and unpaid dividends included in the calculation of (loss applicable) income available to the Company’s common stockholders and the Company’s basic (loss) earnings per share calculation for the years ended December 31, 2015, 2014 and 2013 are presented in the accompanying condensed consolidated statements of operations.

See Note 20 for discussion of the Company’s (loss) earnings per share calculation.

Common Stock

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

The following table presents information regarding the Company’s common stock (in thousands):

	December 31,
	2015	2014
Shares authorized	1,800,000	800,000
Shares outstanding at end of period	633,471	484,819
Shares held in treasury	2,113	1,113

Redemption of Senior Unsecured Notes. During the year ended December 31, 2015, the Company issued approximately 28.0 million shares of common stock in exchange for $50.0 million in Senior Unsecured Notes. See Note 12 for additional discussion of the redemption of Senior Unsecured Notes.

Conversions of Convertible Senior Unsecured Notes. During the year ended December 31, 2015, the Company issued approximately 92.8 million shares of common stock upon the exercise of conversion options by holders of approximately $255.3 million in par value of the Convertible Senior Unsecured Notes. The Company recorded the issuance of common shares at fair value on the various dates the exchanges occurred. See Note 12 for additional discussion of the Convertible Senior Unsecured Notes transactions.

Stock Repurchase Program. In 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 the Company’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 discontinued at any time. Payment for shares repurchased under the program will be funded using the Company's working capital. During the year ended December 31, 2014, 27.4 million shares totaling $111.3 million, net of $0.5 million in broker fees and commissions, 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, the excess of the repurchase price over the par value was fully applied to additional paid-in capital.

Stockholder Rights Plan.On November 19, 2012, the Company’s Board adopted a stockholder rights plan pursuant to which the Board authorized and declared to stockholders of record on November 29, 2012 a dividend of one preferred share purchase right (the “Right”) for each outstanding share of common stock. Effective April 29, 2013, at the direction of the Board, the Company amended a stockholder rights plan, adopted in the fourth quarter of 2012, to accelerate the expiration date of the Rights to April 29, 2013, resulting in the termination of the stockholder rights plan.

See Note 17 for discussion of the Company’s share-based compensation.

Treasury Stock

The Company makes required statutory tax payments on behalf of employees when their restricted stock awards vest and then withholds a number of vested shares of common stock having a value on the date of vesting equal to the tax obligation. The following table shows the number of shares withheld for taxes and the associated value of those shares for the years ended December 31, 2015, 2014 and 2013. These shares were accounted for as treasury stock when withheld, and then immediately retired.

	Year Ended December 31,
	2015		2014		2013
	(In thousands)
Number of shares withheld for taxes	1,872		1,034		5,679
Value of shares withheld for taxes	$	2,428	$	6,373	$	30,126

Shares of Company common stock held as assets in a trust for the Company’s non-qualified deferred compensation plan are accounted for as treasury shares. These shares are not included as outstanding shares of common stock for accounting purposes. For corporate purposes, including for the purpose of voting at Company stockholder meetings, these shares are considered outstanding and have voting rights, which are exercised by the Company.

Stockholder Receivable

The Company is party to a settlement agreement relating to a third-party claim against its former CEO under Section 16(b) of the Securities Exchange Act of 1934, as amended. Based on the nature of the settlement as well as the former CEO’s position as an officer of the Company at the time of the settlement, the receivable related to this settlement is classified as a component of additional paid-in capital in the accompanying consolidated balance sheets. The remaining amount receivable under the agreement as of December 31, 2015 and 2014 was $1.3 million and $2.5 million, respectively.

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Share-Based Compensation

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

Share-Based Compensation

The Company issues share-based compensation awards including restricted common stock awards, restricted stock units, performance units and performance share units under the SandRidge Energy, Inc. 2009 Incentive Plan. Total share-based compensation expense is measured using the grant date fair value for equity-classified awards and using the fair value at period end for liability-classified awards. For the years ended December 31, 2015, 2014 and 2013, the Company recognized share-based compensation expense of $21.7 million, $22.6 million and $90.2 million, respectively, net of $5.9 million, $6.0 million and $5.6 million capitalized, respectively. Amounts recognized during the year ended December 31, 2013 include approximately $48.5 million recognized in connection with the separation of certain former executives from the Company.

Restricted Common Stock Awards

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

	Number of Shares		Weighted- Average Grant Date Fair Value
	(In thousands)
Unvested restricted shares outstanding at December 31, 2012	15,328		$	8.07
Granted	7,462		$	6.32
Vested	(13,395	)	$	7.85
Forfeited / Canceled	(1,752	)	$	7.33
Unvested restricted shares outstanding at December 31, 2013	7,643		$	6.92
Granted	6,367		$	6.17
Vested	(3,432	)	$	7.04
Forfeited / Canceled	(2,022	)	$	6.60
Unvested restricted shares outstanding at December 31, 2014	8,556		$	6.39
Granted	2,928		$	0.88
Vested	(5,186	)	$	4.95
Forfeited / Canceled	(672	)	$	6.38
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85

As of December 31, 2015, the Company’s unrecognized compensation cost related to unvested restricted stock awards was $18.0 million. Such cost is expected to be recognized over a weighted-average period of 1.9 years. The Company’s restricted stock awards are equity-classified awards.

Restricted Stock Units

During the year ended December 31, 2015, the Company granted restricted stock units that vest over a maximum of four years and will be settled in cash, shares of Company common stock or a combination of common stock and cash.

Restricted Stock Units - Settled in Cash or Stock. The following table presents a summary of the Company’s unvested restricted stock units which may be settled in shares of the Company’s common stock, cash or some combination of common stock and cash at the Company’s election. These restricted stock units are liability-classified awards, which vest ratably over a maximum four-year period from the date of grant and were valued at December 31, 2015 based upon the Company’s period end common stock price.

	Number of Units		Fair Value per Unit at December 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	11,095
Vested(1)	(2,200	)
Forfeited / Canceled	(767	)
Unvested units outstanding at December 31, 2015	8,128		$	0.20

____________________

(1) Restricted stock units which vested during the year ended December 31, 2015 were settled by the issuance of common stock.

As of December 31, 2015, the Company’s unrecognized compensation cost related to the unvested restricted stock units noted above was $0.9 million and is expected to be recognized over a weighted-average period of 3.2 years.

Restricted Stock Units - Settled in Cash. The following table presents a summary of the Company’s unvested restricted stock units which will be settled in cash at the end of each vesting period for an amount based on the Company’s common stock price as of the vesting date. These restricted stock units are liability-classified awards and generally vest over a two-year period (40% at the end of the first year and 60% at the end of the second year). The restricted stock units were valued based upon the Company’s period end common stock price, discounted using a credit spread (10.6% at December 31, 2015) that was determined based upon an analysis of the historical option adjusted spread for the Company’s outstanding senior notes and the outstanding long-term debt of comparable companies.

	Number of Units		Fair Value per Unit at December 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	3,104
Vested	(979	)
Forfeited / Canceled	(122	)
Unvested units outstanding at December 31, 2015	2,003		$	0.04	-	$	0.20

As of December 31, 2015, the Company’s unrecognized compensation cost related to unvested two-year restricted stock units was $0.2 million. Such cost is expected to be recognized over a weighted-average period of 1.0 years.

Performance Units and Performance Share Units

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

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

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

	December 31,
	2015			2014
Volatility factor	120.0		%	55.6		%
Weighted-average risk-free interest rate	0.7		%	0.5		%
Weighted-average fair value per unit	$	1.08		$	13.85

Performance unit activity for the years ended December 31, 2015, 2014 and 2013 was as follows (in thousands):

	December 31,
	2015		2014		2013(1)
Outstanding at January 1	66		31		—
Granted	—		47		31
Vested	(28	)	—		—
Forfeited /canceled	—		(12	)	—
Outstanding at December 31	38		66		31
Performance period ending December 31, 2015
Vested	—		9		12
Unvested	—		19		19
Performance period ending December 31, 2016
Vested	26		13		—
Unvested	12		25		—

____________________

(1)    The 2013 performance units fully vested on December 31, 2015, with no amounts paid.

As of December 31, 2015, the Company’s unrecognized compensation cost related to performance units granted in 2014 was insignificant and is expected to be recognized over the remaining 1.0 year term of the awards.

Performance Share Units. During the year ended December 31, 2015, the Company granted performance share units to certain members of senior management. The following table presents a summary of the fair values of the performance share units granted and the related assumptions for all outstanding performance share units at December 31, 2015.

	December 31, 2015
Volatility factor	95.3		%
Weighted-average risk-free interest rate	1.1		%
Weighted-average fair value per unit	$	0.10

Performance share unit activity for the year ended December 31, 2015 was as follows:

	Number of Performance Share Units
	(In thousands)
Outstanding at December 31, 2014	—
Granted	2,044
Forfeited /canceled	(151	)
Outstanding at December 31, 2015	1,893
Performance period ending December 31, 2017
Vested	695
Unvested	1,198

As of December 31, 2015, the Company’s unrecognized compensation cost related to performance share units granted in 2015 units was $0.1 million. Such cost is expected to be recognized over the remaining 2.0 year term of the awards.

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Incentive and Deferred Compensation Plans

12 Months Ended

Dec. 31, 2015

Compensation Related Costs [Abstract]

Incentive and Deferred Compensation Plans

Incentive and Deferred Compensation Plans

Annual Incentive Plan. In June 2013, the Compensation Committee of the Company’s Board approved an annual incentive plan effective June 2013 for all employees and discontinued the Company’s then existing cash bonus program with final payments under the program of approximately $10.9 million made in July 2013. For certain members of management, the annual incentive plan incorporates objective performance criteria, individual performance goals and competitive target award levels for the 2015 performance year with payout percentages ranging from 0% to 200% of specified target levels based on actual performance. As of December 31, 2015 and 2014, the Company had accrued approximately $21.6 million and $21.1 million, respectively, for the annual incentive for all employees, including an accrual for an annual incentive for specified members of management based on actual performance compared to target levels specified in the annual incentive plan. The annual incentive plan was replaced in January 2016 by the Company’s newly-implemented performance incentive plan. See Note 22.

Deferred Compensation Plans. The Company maintains a 401(k) retirement plan for its employees. Under the Plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service (“IRS”). The Company made matching contributions to the plan through cash purchases of Company stock equal to 100% on the first 10% employee deferred wages for the years ended December 31, 2015 and 2014 and 100% on the first 15% of employee deferred wages for the year ended December 31, 2013. Retirement plan expense for the years ended December 31, 2015, 2014 and 2013 was approximately $7.9 million, $8.7 million and $11.0 million, respectively.

The Company maintains a non-qualified deferred compensation plan that allows eligible highly compensated employees to elect to defer income exceeding the IRS annual limitations on qualified 401(k) retirement plans. The Company made matching contributions on non-qualified contributions up to a maximum of 10% of employee compensation for the years ended December 31, 2015 and 2014 and 15% of employee compensation for the year ended December 31, 2013. For the years ended December 31, 2015, 2014 and 2013, employer contributions of cash purchases of Company stock were approximately $2.9 million, $2.0 million and $2.7 million, respectively. Any assets placed in trust by the Company to fund future obligations of the Company’s non-qualified deferred compensation plan are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their own deferred compensation in, and the Company’s contributions to, the plan.

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Income Taxes

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company’s income tax provision (benefit) consisted of the following components for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2015		2014			2013
Current
Federal	$	—	$	(1,160	)	$	3,842
State	123		(1,133		)	1,842
	123		(2,293		)	5,684
Deferred
Federal	—		—			—
State	—		—			—
	—		—			—
Total provision (benefit)	123		(2,293		)	5,684
Less: income tax provision attributable to noncontrolling interest	90		283			308
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	33	$	(2,576	)	$	5,376

A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax benefit is as follows for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	2015			2014			2013
Computed at federal statutory rate	$	(1,512,325	)	$	122,362		$	(178,078	)
State taxes, net of federal benefit	(19,988		)	4,145			(886		)
Non-deductible expenses	816			1,895			2,589
Non-deductible debt costs	10,228			—			—
Stock-based compensation	6,700			1,467			7,611
Net effects of consolidating the non-controlling interests’ tax provisions	218,196			(34,614		)	(13,901		)
Change in valuation allowance	1,296,405			(96,769		)	188,599
Other	1			(1,062		)	(558		)
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	33		$	(2,576	)	$	5,376

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 made 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. As of December 31, 2015, 2014 and 2013 the balance of the valuation allowance was $2.0 billion, $649.6 million, and $753.5 million, respectively. 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 December 31, 2015. Thus, the Company’s effective tax rate and tax expense for the year ended December 31, 2015 continue to be low as a result of the Company not recognizing an income tax benefit associated with its net loss from the same period.

Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):

	December 31,
	2015			2014
Deferred tax liabilities
Investments(1)	$	138,310		$	272,902
Property, plant and equipment	—			364,576
Derivative contracts	30,989			113,735
Long-term debt	10,017			—
Total deferred tax liabilities	179,316			751,213
Deferred tax assets
Property, plant and equipment	807,275			—
Allowance for doubtful accounts	18,702			19,086
Net operating loss carryforwards	1,190,799			1,265,458
Compensation and benefits	18,607			19,867
Alternative minimum tax credits and other carryforwards	44,302			43,840
Asset retirement obligations	38,314			21,946
CO2 under-delivery shortfall penalty	40,654			27,674
Other	4,305			2,934
Total deferred tax assets	2,162,958			1,400,805
Valuation allowance	(1,983,642		)	(649,592		)
Net deferred tax liability	$	—		$	—

____________________

(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. See Note 4 for further discussion of the Royalty Trusts.

As of December 31, 2015, the Company had approximately $9.3 million of alternative minimum tax credits available that do not expire. In addition, the Company had approximately $3.2 billion of federal net operating loss carryovers that expire during the years 2025 through 2035. Excess tax benefits of approximately $17.7 million associated with the vesting of restricted stock awards are included in the federal net operating loss carryovers, but will not be recognized as a tax benefit recorded to additional paid-in capital until realized.

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 an IRC Section 382 limitation. The limitation could result in all or a portion of the remaining $552.6 million limited net operating loss carryforwards expiring unused. The limitation did not result in a current federal tax liability at December 31, 2015.

At December 31, 2015 and 2014, the Company had a liability of approximately $0.1 million for unrecognized tax benefits. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	December 31,
	2015		2014
Unrecognized tax benefit at January 1	$	77	$	1,382
Changes to unrecognized tax benefits related to a prior year	4		(17		)
Decreases to unrecognized tax benefits for settlements with tax authorities	—		(1,288		)
Unrecognized tax benefit at December 31	$	81	$	77

Consistent with its policy to record interest and penalties on income taxes as a component of the income tax provision, the Company has included insignificant amounts of accrued gross interest with respect to unrecognized tax benefits in its accompanying consolidated statements of operations during the years ended December 31, 2015, 2014 and 2013. The Company does not expect a significant change in its gross unrecognized tax benefits balance within the next 12 months.

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

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

(Loss) Earnings per Share

(Loss) Earnings per Share

Basic earnings per share are computed using the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average shares outstanding during the period, but also include the dilutive effect of awards of restricted stock and restricted stock units, using the treasury stock method, and outstanding convertible perpetual preferred stock and convertible senior notes, using the if-converted method. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Net (Loss) Income			Weighted Average Shares	(Loss) Earnings Per Share
	(In thousands, except per share amounts)
Year Ended December 31, 2015
Basic loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Convertible preferred stock(2)	—			—
Convertible senior unsecured notes(3)	—			—
Diluted loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Year Ended December 31, 2014
Basic earnings per share	$	203,260		479,644	$	0.42
Effect of dilutive securities
Restricted stock	—			2,181
Convertible preferred stock(2)	6,500			17,918
Diluted earnings per share	$	209,760		499,743	$	0.42
Year Ended December 31, 2013
Basic loss per share	$	(609,414	)	481,148	$	(1.27	)
Effect of dilutive securities
Restricted stock(4)	—			—
Convertible preferred stock(5)	—			—
Diluted loss per share	$	(609,414	)	481,148	$	(1.27	)

____________________

(1) No incremental shares of potentially dilutive restricted stock awards or units were included for the year ended December 31, 2015 as their effect was antidilutive under the treasury stock method.

(2) Potential common shares related to the Company’s outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.2 million and 71.7 million shares for the years ended December 31, 2015 and 2014, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.

(3) Potential common shares related to the Company’s outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 48.5 million shares for the year ended December 31, 2015 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

(4) Restricted stock awards covering 0.5 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.

(5) Potential common shares related to the Company’s outstanding 8.5%, 6.0% and 7.0% convertible perpetual preferred stock covering 90.1 million shares for the year ended December 31, 2013 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

See Note 16 for discussion of the Company’s convertible perpetual preferred stock.

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Related Party Transactions

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

The Company entered into transactions in the ordinary course of business with certain related parties. These transactions primarily consisted of sales of oil and natural gas. See Note 10 for accounts payable attributable to related party transactions. During the year ended December 31, 2013 sales to related parties were $1.6 million. This amount primarily related to sales of natural gas from the Permian Properties, which were sold in February 2013, to the Company’s partner in GRLP.

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 approximately 6.3 million shares of restricted stock awards during the third quarter of 2013. As of December 31, 2015, the remaining amount due under the terms of his employment agreement include $1.5 million to be paid in monthly installments through December 2016. This amount is included in other current liabilities in the accompanying consolidated balance sheet. See Note 16 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 years ended December 31, 2015, 2014 and 2013. For the years ended December 31, 2015 and 2014, employee termination benefits were $12.5 million and $8.9 million, respectively, primarily as a result of a reduction in workforce and executives’ separation from employment, and the sale of the Gulf Properties. For the year ended December 31, 2013, employee termination benefits, excluding amounts attributable to the Company’s former chairman and CEO, were $23.2 million, primarily as a result of other executives’ separation from employment.

Oklahoma City Thunder Agreements. Until April 2014, the Company’s former Chairman and CEO owned, and one of the Company’s directors currently owns, minority interests in a limited liability company that owns and operates the Oklahoma City Thunder basketball team. The Company was party to a sponsorship agreement, whereby it paid approximately $3.3 million per year for advertising and promotional activities related to the Oklahoma City Thunder, which terminated with the conclusion of the 2012-2013 season.

Office Lease. The Company is party to a commercial lease to rent space in a building owned by an entity that is partially owned by one of the Company’s directors. The terms provide for a lease term through December 2017 with annual rent of approximately $0.5 million. Any renovation costs paid by the Company with respect to the leased space are applied toward future rent payments. As of December 31, 2015, the Company has made renovations costing approximately $3.3 million.

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.

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Subsequent Events

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Royalty Trust Distributions. On January 28, 2016, the Royalty Trusts announced quarterly distributions for the three-month period ended December 31, 2015. The following distributions will be paid on February 26, 2016 to holders of record as of the close of business on February 12, 2016 (in thousands):

Royalty Trust	Total Distribution		Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I	$	8,708	$	6,367
Permian Trust	7,560		7,560
Mississippian Trust II	6,825		5,682
Total	$	23,093	$	19,609

Preferred Stock Dividends. In January 2016, the Company announced the suspension of payment of the semi-annual dividend on shares of its 8.5% convertible perpetual preferred stock.

Performance Incentive Plan. In January 2016, the Company implemented a performance incentive plan. The plan is intended to replace, on a prospective basis, the Company’s annual incentive plan and equity-based long-term incentive awards, such as restricted stock awards and restricted stock units, and provides for quarterly cash payments to participants based upon corporate performance goals with payout percentages ranging from 0% to 200%.

Personnel Reductions and Severance.The Companydiscontinued substantially all remaining drilling and oilfield services operations in January 2016 and completed a reduction in its corporate workforce in February 2016. Estimated severance costs incurred associated with these events totaled approximately $17.4 million through February 2016.

Senior Credit Facility. In January 2016, the Company borrowed the available capacity under the senior credit facility, or $488.9 million. On March 11, 2016, the administrative agent notified the Company that the lenders had elected to reduce the borrowing base to $340.0 million from $500.0 million pursuant to a special redetermination. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties.

As discussed further in Note 1, the report of the Company’s independent registered public accounting firm that accompanies these consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern, which under the terms of the senior credit facility may result in an event of default. If the Company does not obtain a waiver of this requirement or otherwise cure this event within 30 calendar days of the issuance of these consolidated financial statements, the lenders under the senior credit facility will be able to accelerate the maturity of the debt. Any acceleration of the obligations under the senior credit facility would result in a cross-default and potential acceleration of the Company’s other outstanding long-term debt.

Divestiture of WTO Properties and Release from Treating Agreement. On January 21, 2016, the Company paid $11.0 million in cash and transferred ownership of substantially all of its oil and natural gas properties and midstream assets located in the Piñon field in the WTO, including the PGC assets acquired in October 2015, to Occidental and was released from all past, current and future claims and obligations under an existing 30 years treating agreement between the companies. As of December 31, 2015, the Company had accrued approximately $109.9 million for penalties associated with shortfalls in meeting its delivery requirements under the agreement since it became effective in late 2012, including $34.9 million incurred for the year ended December 31, 2015. The Company expects to recognize a loss on the termination of the treating agreement and the cease-use of transportation agreements that support production from the Piñon field, however, is currently obtaining further information needed to evaluate the commitments extinguished and consideration conveyed in the transaction.

Production, proved reserves, revenues and direct operating expenses for the oil and natural gas properties transferred in the transaction were 1.9 MMBoe, 24.6 MMBoe, $14.6 million and $41.1 million, respectively, as of and for the year ended December 31, 2015.

Interest Payments on Long-Term Debt. On February 16, 2016, the Company elected to defer interest payments then due with respect to its 7.5% Senior Notes due 2023 and its Senior Convertible Notes due 2023 (collectively, the “2023 Notes”). On March 15, 2016, the Company made a payment of approximately $22 million in satisfaction of its obligations under the 2023 Notes. Further, on March 16, 2016, the Company made approximately $28.4 million in interest payments then due with respect to its 7.5% Senior Notes due 2021.

Conversions of Long-Term debt to Common Stock. During the period from January 1, 2016 to March 20, 2016, holders of $200.5 million aggregate principal amount of 8.125% Convertible Senior Notes due 2022 and $31.6 million aggregate principal amount of 7.5% Convertible Senior Notes due 2023 exercised conversion options applicable to those notes, resulting in the issuance of approximately 84.4 million shares of Company common stock and aggregate cash payments of $33.5 million for accrued interest and early conversion payments.

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Business Segment Information

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Business Segment Information

Business Segment Information

During the years ended December 31, 2015, 2014 and 2013, the Company had three reportable business segments: exploration and production, drilling and oilfield 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 oilfield services segment is engaged in the contract drilling of oil and natural gas wells and provides various oilfield 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.

As discussed in Note 22, the Company discontinued the substantial majority of activity within its drilling and oilfield services segment in January 2016. The Company is currently evaluating the impact of this event on its segment reporting for periods within the year ending December 31, 2016.

Management evaluates the performance of the Company’s business segments based on (loss) income 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(3)			All Other(4)			Consolidated Total
Year Ended December 31, 2015
Revenues	$	707,446		$	67,358		$	81,083		$	5,342		$	861,229
Inter-segment revenue	(12		)	(45,234		)	(47,274		)	—			(92,520		)
Total revenues	$	707,434		$	22,124		$	33,809		$	5,342		$	768,709
Loss from operations	$	(4,461,907	)	$	(59,999	)	$	(15,218	)	$	(105,554	)	$	(4,642,678	)
Interest expense, net	(42		)	—			—			(321,379		)	(321,421		)
Gain on extinguishment of debt	—			—			—			641,131			641,131
Other income, net	1,368			13			253			406			2,040
Loss before income taxes	$	(4,460,581	)	$	(59,986	)	$	(14,965	)	$	214,604		$	(4,320,928	)
Capital expenditures(5)	$	656,022		$	4,632		$	21,556		$	19,405		$	701,615
Depreciation, depletion, amortization and accretion	$	324,471		$	17,438		$	11,742		$	18,121		$	371,772
At December 31, 2015
Total assets	$	1,959,975		$	27,621		$	254,212		$	749,347		$	2,991,155
Year Ended December 31, 2014
Revenues	$	1,423,073		$	192,944		$	142,987		$	4,376		$	1,763,380
Inter-segment revenue	(173		)	(116,856		)	(87,593		)	—			(204,622		)
Total revenues	$	1,422,900		$	76,088		$	55,394		$	4,376		$	1,558,758
Income (loss) from operations	$	713,716		$	(37,564	)	$	(9,094	)	$	(76,834	)	$	590,224
Interest income (expense), net	100			—			—			(244,209		)	(244,109		)
Other (expense) income, net	(423		)	(541		)	9			4,445			3,490
Income (loss) before income taxes	$	713,393		$	(38,105	)	$	(9,085	)	$	(316,598	)	$	349,605
Capital expenditures(5)	$	1,508,100		$	18,385		$	44,606		$	37,798		$	1,608,889
Depreciation, depletion, amortization and accretion	$	443,573		$	29,105		$	10,085		$	20,260		$	503,023
At December 31, 2014
Total assets	$	6,273,802		$	115,083		$	219,691		$	650,649		$	7,259,225
Year Ended December 31, 2013
Revenues	$	1,834,480		$	187,456		$	179,989		$	3,127		$	2,205,052
Inter-segment revenue	(320		)	(120,815		)	(100,529		)	—			(221,664		)
Total revenues	$	1,834,160		$	66,641		$	79,460		$	3,127		$	1,983,388
Income (loss) from operations	$	62,509		$	(40,155	)	$	(21,567	)	$	(169,788	)	$	(169,001	)
Interest income (expense), net	1,168			—			(209		)	(271,193		)	(270,234		)
Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
Other income (expense), net	5,487			—			(3,222		)	10,180			12,445
Income (loss) before income taxes	$	69,164		$	(40,155	)	$	(24,998	)	$	(512,806	)	$	(508,795	)
Capital expenditures(5)	$	1,319,012		$	7,125		$	55,706		$	42,040		$	1,423,883
Depreciation, depletion, amortization and accretion	$	605,242		$	33,291		$	7,972		$	20,140		$	666,645

____________________

(1) (Loss) income from operations includes full cost ceiling limitation impairments of $4.5 billion and $164.8 million for the years ended December 31, 2015 and 2014, respectively, a loss on the sale of the Permian Properties of $398.9 million for the year ended December 31, 2013 and the Company’s (gain) loss on derivative contracts, including net cash payments upon settlement, for the years ended December 31, 2015, 2014 and 2013. See Note 13 for discussion of derivative contracts.

(2) For the years ended December 31, 2015, 2014 and 2013, (loss) income from operations includes impairments of $37.6 million, $27.4 million, and $11.1 million, respectively, on certain drilling assets.

(3) For the years ended December 31, 2015, 2014 and 2013, (loss) income from operations includes impairments of other midstream assets and the Company’s gas treating plants in west Texas of $7.1 million, $0.6 million and $3.9 million, respectively.

(4) (Loss) income from operations for the year ended December 31, 2015 includes an impairment of $15.4 million on property located in downtown Oklahoma City, Oklahoma and $0.7 million on gathering and compression equipment. See Note 7. For the year ended December 31, 2013, (loss) income from operations includes a $2.9 million impairment of a corporate asset and an $8.3 million impairment of the Company’s CO₂ compression facilities.

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

Major Customers. For the years ended December 31, 2015, 2014 and 2013, the Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):

	2015
	Sales		% of Revenue
Plains Marketing, L.P.	$	318,018	41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649	30.1	%

	2014
	Sales		% of Revenue
Plains Marketing, L.P.	$	597,117	38.3	%
Targa Pipeline Mid-Continent West OK LLC	$	333,027	21.4	%

	2013
	Sales		% of Revenue
Plains Marketing, L.P.	$	491,258	24.8	%
Shell Trading (US) Company	$	347,422	17.5	%
Targa Pipeline Mid-Continent West OK LLC	$	211,838	10.7	%

Plains Marketing, L.P., Targa Pipeline Mid-Continent West OK LLC (formerly Atlas Pipeline Mid-Continent West OK LLC) and Shell Trading (US) Company are purchasers of oil, natural gas and NGLs sold by the Company’s exploration and production segment.

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Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2015

Condensed Consolidating Financial Statements Disclosure [Abstract]

Condensed Consolidating Financial Information

Condensed Consolidating Financial Information

The Company provides condensed consolidating financial information for its subsidiaries that are guarantors of its registered debt. As of December 31, 2015, the subsidiary guarantors, which are 100% owned by the Company, have jointly and severally guaranteed, on a full, unconditional and unsecured basis, the Company’s outstanding Senior Unsecured Notes. The subsidiary guarantees (i) rank equally in right of payment with all of the existing and future senior debt of the subsidiary guarantors; (ii) rank senior to all of the existing and future subordinated debt of the subsidiary guarantors; (iii) are effectively subordinated in right of payment to any existing or future secured obligations of the subsidiary guarantors to the extent of the value of the assets securing such obligations; (iv) are structurally subordinated to all debt and other obligations of the subsidiaries of the guarantors who are not themselves subsidiary guarantors; and (v) are only released under certain customary circumstances. The Company’s subsidiary guarantors guarantee payments of principal and interest under the Company’s registered notes.

Certain of the Company’s wholly owned subsidiaries that were sold in February 2014, as discussed in Note 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.

Condensed Consolidating Balance Sheets

	December 31, 2015
	Parent			Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	426,917		$	847	$	7,824	$	—		$	435,588
Accounts receivable, net	—			122,606		4,781		—			127,387
Intercompany accounts receivable	1,226,994			1,305,573		30,683		(2,563,250		)	—
Derivative contracts	—			84,349		—		—			84,349
Prepaid expenses	—			6,826		7		—			6,833
Other current assets	—			19,931		—		—			19,931
Total current assets	1,653,911			1,540,132		43,295		(2,563,250		)	674,088
Property, plant and equipment, net	—			2,124,532		110,170		—			2,234,702
Investment in subsidiaries	2,749,514			8,531		—		(2,758,045		)	—
Other assets	72,259			16,008		—		(5,902		)	82,365
Total assets	$	4,475,684		$	3,689,203	$	153,465	$	(5,327,197	)	$	2,991,155
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	160,122		$	265,767	$	2,528	$	—		$	428,417
Intercompany accounts payable	1,337,688			1,192,569		32,993		(2,563,250		)	—
Derivative contracts	—			573		—		—			573
Asset retirement obligations	—			8,399		—		—			8,399
Total current liabilities	1,497,810			1,467,308		35,521		(2,563,250		)	437,389
Investment in subsidiaries	1,038,303			400,771		—		(1,439,074		)	—
Long-term debt	3,637,408			—		—		(5,902		)	3,631,506
Asset retirement obligations	—			95,179		—		—			95,179
Other long-term obligations	80			14,734		—		—			14,814
Total liabilities	6,173,601			1,977,992		35,521		(4,008,226		)	4,178,888
Stockholders’ (Deficit) Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,697,917		)	1,711,211		117,944		(1,829,155		)	(1,697,917		)
Noncontrolling interest	—			—		—		510,184			510,184
Total stockholders’ (deficit) equity	(1,697,917		)	1,711,211		117,944		(1,318,971		)	(1,187,733		)
Total liabilities and stockholders’ (deficit) equity	$	4,475,684		$	3,689,203	$	153,465	$	(5,327,197	)	$	2,991,155

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

____________________

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

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

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

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2015
Total revenues	$	—		$	682,778		$	85,939		$	(8	)	$	768,709
Expenses
Direct operating expenses	—			364,483			10,879			(8		)	375,354
General and administrative	213			145,796			4,157			—			150,166
Depreciation, depletion, amortization and accretion	—			339,647			32,125			—			371,772
Impairment	—			3,599,810			934,879			—			4,534,689
Gain on derivative contracts	—			(65,049		)	(8,012		)	—			(73,061		)
Loss on settlement of contract	—			50,976			—			—			50,976
Loss (gain) on sale of assets	—			2,217			(726		)	—			1,491
Total expenses	213			4,437,880			973,302			(8		)	5,411,387
Loss from operations	(213		)	(3,755,102		)	(887,363		)	—			(4,642,678		)
Equity earnings from subsidiaries	(4,017,082		)	(263,847		)	—			4,280,929			—
Interest expense, net	(321,378		)	(43		)	—			—			(321,421		)
Gain on extinguishment of debt	641,131			—			—			—			641,131
Other income, net	—			1,910			130			—			2,040
Loss before income taxes	(3,697,542		)	(4,017,082		)	(887,233		)	4,280,929			(4,320,928		)
Income tax expense	3			—			120			—			123
Net loss	(3,697,545		)	(4,017,082		)	(887,353		)	4,280,929			(4,321,051		)
Less: net loss attributable to noncontrolling interest	—			—			—			(623,506		)	(623,506		)
Net loss attributable to SandRidge Energy, Inc.	$	(3,697,545	)	$	(4,017,082	)	$	(887,353	)	$	4,904,435		$	(3,697,545	)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2014
Total revenues	$	—		$	1,341,531		$	217,367		$	(140	)	$	1,558,758
Expenses
Direct operating expenses	—			467,175			16,854			(140		)	483,889
General and administrative	331			118,249			4,285			—			122,865
Depreciation, depletion, amortization and accretion	—			446,149			56,874			—			503,023
Impairment	—			150,125			42,643			—			192,768
Gain on derivative contracts	—			(292,733		)	(41,278		)	—			(334,011		)
Total expenses	331			888,965			79,378			(140		)	968,534
(Loss) income from operations	(331		)	452,566			137,989			—			590,224
Equity earnings from subsidiaries	495,154			38,967			—			(534,121		)	—
Interest (expense) income, net	(244,209		)	100			—			—			(244,109		)
Other income (expense), net	—			3,521			(31		)	—			3,490
Income before income taxes	250,614			495,154			137,958			(534,121		)	349,605
Income tax (benefit) expense	(2,671		)	—			378			—			(2,293		)
Net income	253,285			495,154			137,580			(534,121		)	351,898
Less: net income attributable to noncontrolling interest	—			—			—			98,613			98,613
Net income attributable to SandRidge Energy, Inc.	$	253,285		$	495,154		$	137,580		$	(632,734	)	$	253,285

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Total revenues	$	—		$	1,675,481		$	308,300		$	(393	)	$	1,983,388
Expenses
Direct operating expenses	—			654,080			29,143			(393		)	682,830
General and administrative	329			323,808			6,288			—			330,425
Depreciation, depletion, amortization and accretion	—			581,435			85,210			—			666,645
Impairment	—			15,038			11,242			—			26,280
Loss on derivative contracts	—			24,702			22,421			—			47,123
Loss on sale of assets	—			291,743			107,343			—			399,086
Total expenses	329			1,890,806			261,647			(393		)	2,152,389
(Loss) income from operations	(329		)	(215,325		)	46,653			—			(169,001		)
Equity earnings from subsidiaries	(195,118		)	3,075			—			192,043			—
Interest (expense) income, net	(271,193		)	959			—			—			(270,234		)
Loss on extinguishment of debt	(82,005		)	—			—			—			(82,005		)
Other income (expense), net	—			16,173			(3,728		)	—			12,445
(Loss) income before income taxes	(548,645		)	(195,118		)	42,925			192,043			(508,795		)
Income tax expense	5,244			—			440			—			5,684
Net (loss) income	(553,889		)	(195,118		)	42,485			192,043			(514,479		)
Less: net income attributable to noncontrolling interest	—			—			—			39,410			39,410
Net (loss) income attributable to SandRidge Energy, Inc.	$	(553,889	)	$	(195,118	)	$	42,485		$	152,633		$	(553,889	)

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2015
Net cash (used in) provided by operating activities	$	(326,674	)	$	524,313		$	124,626		$	51,272		$	373,537
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(879,201		)	—			—			(879,201		)
Acquisition of assets	—			(216,943		)	—			—			(216,943		)
Other	—			74,140			907			(18,543		)	56,504
Net cash (used in) provided by investing activities	—			(1,022,004		)	907			(18,543		)	(1,039,640		)
Cash flows from financing activities
Proceeds from borrowings	2,065,000			—			—			—			2,065,000
Repayments of borrowings	(939,466		)	—			—			—			(939,466		)
Distributions to unitholders	—			—			(158,629		)	20,324			(138,305		)
Intercompany (advances) borrowings, net	(475,618		)	497,140			(21,522		)	—			—
Other	(66,793		)	—			53,055			(53,053		)	(66,791		)
Net cash provided by (used in) financing activities	583,123			497,140			(127,096		)	(32,729		)	920,438
Net increase (decrease) in cash and cash equivalents	256,449			(551		)	(1,563		)	—			254,335
Cash and cash equivalents at beginning of year	170,468			1,398			9,387			—			181,253
Cash and cash equivalents at end of year	$	426,917		$	847		$	7,824		$	—		$	435,588

	Parent(1)			Guarantors(1)(2)			Non-Guarantors			Eliminations(2)			Consolidated
	(In thousands)
Year Ended December 31, 2014
Net cash (used in) provided by operating activities	$	(240,932	)	$	641,181		$	212,427		$	8,438		$	621,114
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(1,553,332		)	—			—			(1,553,332		)
Proceeds from sale of assets	—			711,728			2,747			—			714,475
Other	—			28,256			1,140			(47,780		)	(18,384		)
Net cash (used in) provided by investing activities	—			(813,348		)	3,887			(47,780		)	(857,241		)
Cash flows from financing activities
Distributions to unitholders	—			—			(234,327		)	40,520			(193,807		)
Repurchase of common stock	(111,827		)	—			—			—			(111,827		)
Intercompany (advances) borrowings, net	(215,368		)	215,373			(5		)	—			—
Other	(66,910		)	(42,821		)	19,260			(1,178		)	(91,649		)
Net cash (used in) provided by financing activities	(394,105		)	172,552			(215,072		)	39,342			(397,283		)
Net (decrease) increase in cash and cash equivalents	(635,037		)	385			1,242			—			(633,410		)
Cash and cash equivalents at beginning of year	805,505			1,013			8,145			—			814,663
Cash and cash equivalents at end of year	$	170,468		$	1,398		$	9,387		$	—		$	181,253

____________________

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

(2) Other investing activities for the Guarantor has increased to correctly exclude $193.8 million in noncontrolling interest distributions, with a corresponding decrease for Eliminations for this same line item. In addition, other financing activities for the Guarantor, has decreased to correctly exclude $193.8 million of noncontrolling interest distributions, with a corresponding increase for Eliminations for the same line item. The corrections did not result in any changes to consolidated net cash (used in) provided by investing activities or net cash used in financing activities.

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Net cash (used in) provided by operating activities	$	(239,026	)	$	852,026		$	254,723		$	907		$	868,630
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(1,496,731		)	—			—			(1,496,731		)
Proceeds from sale of assets	—			2,566,742			17,373			—			2,584,115
Other	—			89,606			3,197			(109,831		)	(17,028		)
Net cash used in investing activities	—			1,159,617			20,570			(109,831		)	1,070,356
Cash flows from financing activities
Repayments of borrowings	(1,115,500		)	—			—			—			(1,115,500		)
Premium on debt redemption	(61,997		)	—			—			—			(61,997		)
Distributions to unitholders	—			—			(299,675		)	93,205			(206,470		)
Dividends paid—preferred	(55,525		)	—			—			—			(55,525		)
Intercompany borrowings (advances) , net	2,009,146			(2,018,212		)	9,066			—			—
Other	(31,821		)	6,660			14,845			15,719			5,403
Net cash provided by (used in) financing activities	744,303			(2,011,552		)	(275,764		)	108,924			(1,434,089		)
Net increase (decrease) in cash and cash equivalents	505,277			91			(471		)	—			504,897
Cash and cash equivalents at beginning of year	300,228			922			8,616			—			309,766
Cash and cash equivalents at end of year	$	805,505		$	1,013		$	8,145		$	—		$	814,663

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Supplemental Information on Oil and Natural Gas Producing Activities

12 Months Ended

Dec. 31, 2015

Extractive Industries [Abstract]

Supplemental Information on Oil and Natural Gas Producing Activities

Supplemental Information on Oil and Natural Gas Producing Activities

The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):

	December 31,
	2015			2014			2013
Oil and natural gas properties
Proved	$	12,529,681		$	11,707,147		$	10,972,816
Unproved	363,149			290,596			531,606
Total oil and natural gas properties	12,892,830			11,997,743			11,504,422
Less accumulated depreciation, depletion and impairment	(11,149,888		)	(6,359,149		)	(5,762,969		)
Net oil and natural gas properties capitalized costs	$	1,742,942		$	5,638,594		$	5,741,453

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):

	Year Ended December 31,
	2015		2014		2013
Acquisitions of properties
Proved	$	35,376	$	73,370	$	21,130
Unproved	210,065		123,649		100,242
Exploration(1)	29,297		41,070		82,775
Development	571,562		1,288,395		1,131,269
Total cost incurred	$	846,300	$	1,526,484	$	1,335,416

____________________

(1) Includes seismic costs of $7.1 million, $10.8 million and $6.7 million for 2015, 2014 and 2013, respectively.

Results of Operations for Oil and Natural Gas Producing Activities (Unaudited)

The Company’s results of operations from oil and natural gas producing activities for each of the years 2015, 2014 and 2013 are shown in the following table (in thousands):

	Year Ended December 31,
	2015			2014(1)			2013
Revenues	$	707,434		$	1,420,879		$	1,820,278
Expenses
Production costs	324,141			377,819			548,719
Depreciation and depletion	319,913			434,295			567,732
Accretion of asset retirement obligations	4,477			9,092			36,777
Impairment	4,473,787			164,779			—
Total expenses	5,122,318			985,985			1,153,228
(Loss) income before income taxes	(4,414,884		)	434,894			667,050
Income tax expense (benefit)(2)	126			(2,852		)	(7,471		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	(4,415,010	)	$	437,746		$	674,521

____________________

(1) Total expenses increased by $164.8 million and benefit of income taxes decreased by $1.1 million to correctly include the impact of the ceiling test impairment incurred during the year ended December 31, 2014.

(2) Reflects the Company’s effective tax rate for each period.

Oil, Natural Gas and NGL Reserve Quantities (Unaudited)

Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:

• the quality and quantity of available data and the engineering and geological interpretation of that data;

• estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;

• the accuracy of mandated economic assumptions such as the future prices of oil, natural gas and NGLs; and

• the judgment of the personnel preparing the estimates.

Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

The table below represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Estimates of the substantial majority of the Company’s proved reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.

Cawley, Gillespie & Associates, Inc. (“CG&A”), Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2015, 2014 and 2013. CG&A, Ryder Scott and Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. CG&A and Netherland Sewell prepared the estimates of proved reserves for a majority of the Company’s properties as of December 31, 2015. The remaining 9.9% of estimates of proved reserves was based on Company estimates.

The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

2015 Activity. During 2015, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 9.7 MMBbls, 9.3 MMBbls, and 160.9 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Acquisition of the Rockies assets, located in Jackson County, Colorado, in December 2015 added 27.6 MMBoe of reserves. These positive revisions were offset by (i) negative pricing revisions of approximately 54 MMBbls for oil, 36 MMBbls for NGLs and 687 Bcf for natural gas, due primarily to significantly lower commodity prices in 2015, and (ii) negative revisions of approximately 16 MMBbls for oil, 1 MMBbls for NGLs and 74 Bcf for natural gas primarily from well performance in the Mid-Continent.

2014 Activity. During 2014, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 37.6 MMBbls, 27.5 MMBbls, and 467.2 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Revisions of previous estimates decreased oil reserves by 18.7 MMBbls, primarily comprised of (i) approximately 9 MMBbls from Permian Basin proved undeveloped reserves, largely due to removal of drilling locations not expected to be drilled within a five year period, (ii) approximately 8 MMBbls from well performance in the Mid-Continent and (iii) approximately 2 MMBbls from acreage losses or revisions to well interest ownerships. These negative revisions were offset by positive revisions to NGL and gas reserves of 11.1 MMBbls and 167.6 Bcf, respectively, primarily from well performance in the Mid-Continent area. Acquisitions of reserves added 3.5 MMBoe.

Sales of proved reserves during 2014 totaled 55.5 MMBoe from the sale of the Gulf Properties.

2013 Activity. The Company sold its Permian Properties in February 2013. Proved reserves were 198.9 MMBoe, 55% of which were proved developed reserves, for the Permian Properties at December 31, 2012. Estimated standardized measure of discounted cash flows for the Permian Properties, determined by allocating the Company's standardized measure of discounted cash flows to the Permian Properties based on the present value of discounted cash flows attributable to the Permian Properties relative to the Company's total present value of discounted cash flows was $2.5 billion. See Note 3 for additional information regarding the sale. The Company recognized an increase of 119.2 MMBoe in total reserves primarily attributable to extensions and discoveries associated with successful drilling in the Mississippian formation in the Mid-Continent.

The summary below presents changes in the Company’s estimated reserves for 2013, 2014 and 2015.

	Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2012	262,045		67,994		1,415,042
Revisions of previous estimates	(13,969	)	3,717		(53,432	)
Acquisitions of new reserves	43		13		363
Extensions and discoveries	40,570		18,686		359,918
Sales of reserves in place	(131,769	)	(29,067	)	(228,229	)
Production	(14,279	)	(2,291	)	(103,233	)
As of December 31, 2013(2)	142,641		59,052		1,390,429
Revisions of previous estimates	(18,687	)	11,103		167,589
Acquisitions of new reserves	1,009		441		12,527
Extensions and discoveries	37,603		27,500		467,185
Sales of reserves in place	(25,659	)	(2,516	)	(163,800	)
Production	(10,876	)	(3,794	)	(85,697	)
As of December 31, 2014(2)	126,031		91,786		1,788,233
Revisions of previous estimates	(70,708	)	(37,384	)	(759,106	)
Acquisitions of new reserves	22,447		2,460		15,952
Extensions and discoveries	9,741		9,257		160,865
Production	(9,600	)	(5,044	)	(92,104	)
As of December 31, 2015(2)	77,911		61,075		1,113,840
Proved developed reserves
As of December 31, 2012	136,605		33,785		896,701
As of December 31, 2013	83,893		35,807		951,609
As of December 31, 2014	79,022		56,823		1,203,447
As of December 31, 2015	48,639		51,089		964,617
Proved undeveloped reserves
As of December 31, 2012	125,440		34,209		518,341
As of December 31, 2013	58,748		23,245		438,820
As of December 31, 2014	47,009		34,963		584,786
As of December 31, 2015	29,272		9,986		149,223

____________________

(1) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

(2) Includes proved reserves attributable to noncontrolling interests at December 31, 2015, 2014 and 2013 as shown in the table below:

	December 31,
	2015	2014	2013
Oil (MBbl)	7,004	11,027	13,569
NGL (MBbl)	3,694	4,761	4,737
Natural gas (MMcf)	50,508	70,833	69,693

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas (“ASC Topic 932”). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:

• the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;

• pricing is applied based upon 12-month average market prices at December 31, 2015, 2014 and 2013 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:

	At December 31,
	2015		2014		2013
Oil (per barrel)	$	45.29	$	91.65	$	95.67
NGL (per barrel)	$	12.68	$	32.79	$	31.40
Natural gas (per Mcf)	$	1.87	$	3.61	$	3.65

• future development and production costs are determined based upon actual cost at year-end;

• the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and

• a discount factor of 10% per year is applied annually to the future net cash flows.

The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).

	At December 31,
	2015			2014			2013
Future cash inflows from production	$	6,387,944		$	21,022,320		$	19,937,484
Future production costs	(2,731,542		)	(6,499,366		)	(6,843,713		)
Future development costs(1)	(838,945		)	(1,810,201		)	(2,546,680		)
Future income tax expenses	(901		)	(3,223,740		)	(2,283,541		)
Undiscounted future net cash flows	2,816,556			9,489,013			8,263,550
10% annual discount	(1,501,994		)	(5,401,261		)	(4,245,939		)
Standardized measure of discounted future net cash flows(2)	$	1,314,562		$	4,087,752		$	4,017,611

____________________

(1) Includes abandonment costs.

(2) Includes approximately $224.6 million, $643.3 million and $781.6 million attributable to noncontrolling interests at December 31, 2015, 2014 and 2013 respectively.

The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):

Present value as of December 31, 2012	$	5,840,368
Changes during the year
Revenues less production and other costs	(1,271,559		)
Net changes in prices, production and other costs	271,566
Development costs incurred	474,275
Net changes in future development costs	(207,729		)
Extensions and discoveries	1,406,102
Revisions of previous quantity estimates	(296,418		)
Accretion of discount	711,385
Net change in income taxes	477,328
Purchases of reserves in-place	1,628
Sales of reserves in-place	(3,172,187		)
Timing differences and other(1)	(217,148		)
Net change for the year	(1,822,757		)
Present value as of December 31, 2013(2)	4,017,611
Changes during the year
Revenues less production and other costs	(1,043,060		)
Net changes in prices, production and other costs	331,694
Development costs incurred	364,262
Net changes in future development costs	(341,183		)
Extensions and discoveries	1,785,963
Revisions of previous quantity estimates	(77,688		)
Accretion of discount	477,458
Net change in income taxes	(256,371		)
Purchases of reserves in-place	50,958
Sales of reserves in-place	(1,058,330		)
Timing differences and other(1)	(163,562		)
Net change for the year	70,141
Present value as of December 31, 2014(2)	4,087,752
Changes during the year
Revenues less production and other costs	(383,293		)
Net changes in prices, production and other costs	(3,813,465		)
Development costs incurred	217,596
Net changes in future development costs	273,437
Extensions and discoveries	230,055
Revisions of previous quantity estimates	(1,354,778		)
Accretion of discount	512,483
Net change in income taxes	1,426,333
Purchases of reserves in-place	18,429
Sales of reserves in-place	—
Timing differences and other(1)	100,013
Net change for the year	(2,773,190		)
Present value as of December 31, 2015(2)	$	1,314,562

____________________

(1) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2) Includes approximately $224.6 million, $643.3 million and $781.6 million attributable to noncontrolling interests at December 31, 2015, 2014, and 2013 respectively.

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Quarterly Financial Results (Unaudited)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Results (Unaudited)

Quarterly Financial Results (Unaudited)

The Company’s operating results for each quarter of 2015 and 2014 are summarized below (in thousands, except per share data).

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2015
Total revenues	$	215,308		$	229,607		$	180,152		$	143,642
Loss from operations(1)(2)	$	(1,088,456	)	$	(1,535,083	)	$	(1,059,733	)	$	(959,406	)
Net loss(1)(2)	$	(1,151,874	)	$	(1,588,731	)	$	(796,485	)	$	(783,961	)
Loss applicable to SandRidge Energy, Inc. common stockholders(1)(2)	$	(1,045,834	)	$	(1,375,556	)	$	(649,526	)	$	(664,579	)
Loss applicable per share to SandRidge Energy, Inc. common stockholders(3)
Basic	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
Diluted	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
2014
Total revenues	$	443,056		$	374,714		$	394,107		$	346,881
(Loss) income from operations(4)(5)	$	(82,330	)	$	42,079		$	256,491		$	373,984
Net (loss) income(4)(5)	$	(142,406	)	$	(17,252	)	$	197,499		$	314,057
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(4)(5)	$	(150,217	)	$	(46,775	)	$	145,957		$	254,295
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders(3)
Basic	$	(0.31	)	$	(0.10	)	$	0.30		$	0.55
Diluted	$	(0.31	)	$	(0.10	)	$	0.27		$	0.48

____________________

(1) Includes impairment of $1.1 billion, $1.5 billion, $1.1 billion and $886.8 million for the first, second, third and fourth quarters, respectively. See Note 8 for further discussion of impairment.

(2) Includes (gain) loss on derivative contracts of $(49.8) million, $33.0 million, $(42.2) million and $(14.0) million for the first, second, third and fourth quarters, respectively.

(3) (Loss applicable) income available per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of (loss applicable) income available per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

(4) Includes a full cost ceiling limitation impairment of $164.8 million in the first quarter and impairments of drilling assets of $3.1 million and $24.3 million in the second and fourth quarters, respectively.

(5) Includes loss (gain) on derivative contracts of $42.5 million, $85.3 million, $(132.6) million and $(329.2) million for the first, second, third and fourth quarters, respectively.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business

Nature of Business. SandRidge Energy, Inc. is an energy 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 the Rockies in Colorado. The Company also operates businesses and infrastructure systems that are complementary to its primary exploration and production activities, including gas gathering and processing facilities, marketing operations, a saltwater gathering and disposal system, an electrical transmission system and a drilling and related oilfield services business.

Principles of Consolidation

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

Substantial Doubt About Going Concern Disclosure

Going Concern. The Company depends on cash flows from operating activities and, as necessary and available, borrowings under its senior secured revolving credit facility (the “senior credit facility”) to fund its capital expenditures. Additionally, the Company historically has used 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.

The market price for oil, natural gas and natural gas liquids (“NGLs”) decreased significantly beginning in the fourth quarter of 2014, continuing throughout 2015, and into 2016. The decrease in the market price for production directly reduces the Company’s cash flow from operations and indirectly impacts its other potential sources of funds described above. As discussed in Note 22, the Company borrowed all of its remaining available capacity under the senior credit facility in January 2016 and in March 2016, the lenders under the senior credit facility elected to reduce the borrowing base to $340.0 million. On March 21, 2016, the Company notified the administrative agent that the Company would submit for the administrative agent’s consideration proposed additional oil and gas properties to serve as collateral under the senior credit facility sufficient to support a borrowing base of $500.0 million. Additionally, the Company notified the administrative agent that it believed the currently pledged assets are sufficient to support a borrowing base of $500.0 million and reserved the right to exercise all other options available to remedy the borrowing base deficiency, if any. The Company has until April 20, 2016 to submit such additional properties. Lower market prices for production may result in further reductions to the borrowing base under the senior credit facility or higher borrowing costs from other potential sources of financing as the Company’s borrowing capacity and borrowing costs are generally related to the value of the Company’s estimated proved reserves. The weakness in pricing may also impact the Company’s ability to negotiate asset monetizations at acceptable prices.

As a result of the impacts to the Company’s financial position resulting from declining industry conditions and in consideration of the substantial amount of long-term debt outstanding, the Company has engaged advisors to assist with the evaluation of strategic alternatives, which may include, but not be limited to, seeking a restructuring, amendment or refinancing of existing debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code. However, there can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its financial position or complete any strategic transactions. As a result of these uncertainties and the likelihood of a restructuring or reorganization, management has concluded that there is substantial doubt regarding the Company’s ability to continue as a going concern as it is currently structured.

As a result, the report of the Company’s independent registered public accounting firm that accompanies these consolidated financial statements for the year ended December 31, 2015 contains an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern, which under the terms of the senior credit facility may result in an event of default. If the Company does not obtain a waiver of this requirement or otherwise cure this event within 30 calendar days of the issuance of these financial statements, the lenders under the senior credit facility will be able to accelerate maturity of the debt. Any acceleration of the obligations under the senior credit facility would result in a cross-default and potential acceleration of the maturity of the Company’s other outstanding long-term debt. These defaults create additional uncertainty associated with the Company’s ability to repay its outstanding long-term debt obligations as they become due and further reinforces the substantial doubt over the Company’s ability to continue as a going concern.

The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern.

Variable Interest Entities

Variable Interest Entities. An entity is referred to as a VIE if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. The Company consolidates a VIE when it has determined it is the primary beneficiary, which requires significant judgment. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE and the significance of the variable interest, the Company performs a qualitative analysis of the entity’s design, organizational structure, primary decision makers and related financial agreements. In addition to the VIEs that the Company consolidates, until October 2015, the Company also held a variable interest in another VIE that it did not consolidate 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.

Reclassifications

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

Use of Estimates

Use of Estimates. The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The more significant areas requiring the use of assumptions, judgments and estimates include: oil, natural gas and NGL reserves; cash flow estimates used in the valuations of guarantees; impairment tests of long-lived assets; depreciation, depletion and amortization; asset retirement obligations; determinations of significant alterations to the full cost pool and related estimates of fair value used to allocate the full cost pool net book value to divested properties, as necessary; income taxes; valuation of derivative instruments; contingencies; and accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ significantly.

Cash and Cash Equivalents

Cash and Cash Equivalents. The Company considers all highly-liquid instruments with an original maturity of three months or less to be cash equivalents as these instruments are readily convertible to known amounts of cash and bear insignificant risk of changes in value due to their short maturity period.

Accounts Receivable, Net

Accounts Receivable, Net. The Company has receivables for sales of oil, natural gas and NGLs, as well as receivables related to the exploration, production and treating services for oil and natural gas. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Refer to Note 6 for further information on the Company’s accounts receivable and allowance for doubtful accounts.

Fair Value of Financial Instruments

Fair Value of Financial Instruments. Certain of the Company’s financial assets and liabilities are measured at fair value. Fair value represents the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The Company’s financial instruments, not otherwise recorded at fair value, consist primarily of cash, trade receivables, trade payables and long-term debt. The carrying value of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of these instruments. See Note 5 for further discussion of the Company’s fair value measurements.

Fair Value of Non-financial Assets and Liabilities

Fair Value of Non-financial Assets and Liabilities. The Company also applies fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and natural gas production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. The Company may use the present value of estimated future cash inflows and/or outflows or third-party offers or prices of comparable assets with consideration of current market conditions to value its non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in Note 5.

Derivative Financial Instruments

Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil and natural gas production, the Company enters into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. The Company may also, from time to time, enter into interest rate swaps in order to manage risk associated with its exposure to variable interest rates. Additionally, the Company has derivatives related to its 8.75% Senior Secured Notes due 2020 (“Senior Secured Notes”) and its 8.125% Convertible Senior Notes due 2022 and 7.5% Convertible Senior Notes due 2023 (collectively, “Convertible Senior Unsecured Notes”) that are recorded at fair value each reporting period. Refer to Notes 5 and 13 for further information on derivatives associated with the Company’s long-term debt.

The Company recognizes its derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. The Company has elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, accounts for its commodity derivative contracts at fair value with changes in fair value reported currently in earnings. The Company nets derivative assets and liabilities whenever it has a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of the Company’s derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statements of cash flows. See Note 13 for further discussion of the Company’s derivatives.

Oil and Natural Gas Operations

Oil and Natural Gas Operations. The Company uses the full cost method to account for its oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. These capitalized costs include costs of unproved properties and internal costs directly related to the Company’s acquisition, exploration and development activities and capitalized interest. The Company capitalized internal costs of $45.1 million, $55.4 million and $74.7 million to the full cost pool during the years ended December 31, 2015, 2014 and 2013, respectively. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

Costs associated with unproved properties are excluded from the amortizable cost base until a determination has been made as to the existence of proved reserves. Unproved properties are reviewed at the end of each quarter to determine whether the costs incurred should be reclassified to the full cost pool and, thereby, subjected to amortization. The costs associated with unproved properties relate primarily to costs to acquire unproved acreage. Unproved leasehold costs are transferred to the amortization base with the costs of drilling the related well upon determination of the existence of proved reserves or upon impairment of a lease. All items classified as unproved property are assessed, on an individual basis or as a group if properties are individually insignificant, on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of various factors, including, but not limited to, the following: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. Costs of seismic data are allocated to various unproved leaseholds and transferred to the amortization base with the associated leasehold costs on a specific project basis.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down cannot be reversed at a later date.

The ceiling limitation calculation is prepared using the 12-month oil and natural gas average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil and natural gas. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although the Company historically has not designated any of its derivative contracts as cash flow hedges and has therefore not included its derivative contracts in estimating future cash flows. The future cash outflows associated with future development or abandonment of wells are included in the computation of the discounted present value of future net revenues for purposes of the ceiling limitation calculation.

Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center.

Property, Plant and Equipment, Net

Property, Plant and Equipment, Net. Other capitalized costs, including drilling equipment, natural gas gathering and treating equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful lives of the assets, which range from 10 to 39 years for buildings and 3 to 30 years for equipment. When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed and any resulting gain or loss is reflected in the consolidated statements of operations.

Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying value of such asset may not be recoverable. Assets are considered to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any, is less than the carrying amount of the asset or asset group. If an asset or asset group is considered to be impaired, the impairment loss is measured as the amount by which the carrying amount of the asset or asset group exceeds its fair value. See Note 8 for further discussion of impairments.

Capitalized Interest

Capitalized Interest. Interest is capitalized on assets being made ready for use using a weighted average interest rate based on the Company’s borrowings outstanding during that time.

Debt Issuance Costs

Debt Issuance Costs. The Company amortizes debt issuance costs related to its long-term debt as interest expense over the scheduled maturity period of the related debt. The Company includes unamortized debt issuance costs in other assets in the consolidated balance sheets. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.

Investments

Investments. Investments in marketable equity securities have been designated as available for sale and measured at fair value pursuant to the fair value option which requires unrealized gains and losses be reported in earnings.

Asset Retirement Obligations

Asset Retirement Obligations. The Company owns oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statements of operations. The Company determines its asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See Note 14 for further discussion of the Company’s asset retirement obligations.

Revenue Recognition

The Company recognizes revenues and expenses generated from daywork and footage drilling contracts as the services are performed as the Company does not bear the risk of completion of the well. The Company may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees received and costs incurred to mobilize a rig from one location to another are recognized at the time mobilization services are performed.

In general, natural gas purchased and sold by the midstream business is priced at a published daily or monthly index price. Sales to wholesale customers typically incorporate a premium for managing their transmission and balancing requirements. Midstream services revenues are recognized upon delivery of natural gas to customers and/or when services are rendered, pricing is determined and collectability is reasonably assured. Revenues from third-party midstream services are presented on a gross basis, since the Company acts as a principal by taking ownership of the natural gas purchased and taking responsibility of fulfillment for natural gas volumes sold.

Revenue Recognition and Natural Gas Balancing. Sales of oil, natural gas and NGLs are recorded when title of oil, natural gas and NGL production passes to the customer, net of royalties, discounts and allowances, as applicable. Taxes assessed by governmental authorities on oil, natural gas and NGL sales are presented separately from such revenues and included in production tax expense in the consolidated statements of operations.

Natural Gas Balancing

The Company accounts for natural gas production imbalances using the sales method, whereby it recognizes revenue on all natural gas sold to its customers notwithstanding the fact that its ownership may be less than 100% of the natural gas sold. Liabilities are recorded for imbalances greater than the Company’s proportionate share of remaining estimated natural gas reserves. The Company has recorded a liability for natural gas imbalance positions related to natural gas properties with insufficient proved reserves of $1.5 million and $1.4 million at December 31, 2015 and 2014, respectively. The Company includes the gas imbalance positions in other long-term obligations in the consolidated balance sheets.

Revenue Recognition, Construction Contracts

The Company accounted for its construction contract, discussed in Note 11, using the completed-contract method, under which contract revenues and costs are recognized when work under the contract is completed or substantially completed and assets have been transferred. In the interim, costs incurred on and billings related to contracts in process are accumulated on the balance sheet. Contract losses are recorded at the time it is determined that a loss will be incurred. Contract gains, if any, are recorded upon substantial completion of the construction project.

Stock-based Compensation

Share-Based Compensation. The Company may grant restricted stock awards to members of its Board of Directors (the “Board”) and its employees. Such awards and the related stock-based compensation cost are measured based on the calculated fair value of the award on the grant date. The expense, net of estimated forfeitures, is recognized on a straight-line basis over the employee’s requisite service period, generally the vesting period of the award.

The Company grants restricted stock units to members of the Board and its employees. Such awards are settled in cash, shares of Company common stock or a combination of common stock and cash. Restricted stock units vest over a maximum four-year period from the grant date and are valued based upon the Company’s stock price at each period end.

To the extent stock-based compensation cost relates to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statements of operations. The related excess tax benefit received upon vesting of restricted stock, if any, is reflected in the consolidated statements of cash flows as a financing activity. The related excess tax expense due upon vesting of restricted stock, if any, is reflected in the consolidated statements of cash flows as an operating activity.

Performance Unit Compensation. The Company awards performance units and performance share units, which contain a market-based performance component with cash settlement at the end of the performance period, to certain members of senior management. The Company recognizes a liability and expense for performance unit compensation for the portion earned over the requisite service period in an amount equal to the fair value of the performance units granted. Changes in the fair value of the units for which the service requirement has been met are recognized as compensation expense with a corresponding adjustment to the liability. To the extent performance unit compensation cost relates to those directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized are recognized as general and administrative expense, production expense, cost of sales and midstream and marketing expense in the consolidated statements of operations.

Advertising Costs

Advertising Costs. The Company expenses advertising costs as incurred.

Income Taxes

Income Taxes. Deferred income taxes reflect the net tax effects of temporary differences between the amounts of assets and liabilities reported for financial statement purposes and their tax basis. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.

The Company has elected an accounting policy in which interest and penalties on income taxes are presented as a component of the income tax provision, rather than as a component of interest expense. Interest and penalties resulting from the underpayment or the late payment of income taxes due to a taxing authority and interest and penalties accrued relating to income tax contingencies, if any, are presented, on a net of tax basis, as a component of the income tax provision.

Earnings per Share

Earnings per Share. Basic earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by dividing earnings available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculation consist of unvested restricted stock awards and restricted share units, using the treasury method, and convertible preferred stock and convertible senior notes, using the if-converted method. Under the treasury method, the amount of unrecognized compensation expense related to unvested stock-based compensation grants is assumed to be used to repurchase shares at the average market price. Under the if-converted method, the Company assumes the conversion of the preferred stock or convertible senior notes to common stock and determines if it is more dilutive than including the preferred stock dividends or expense associated with the convertible senior notes, respectively, in the computation of income available to common stockholders. When a loss exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 20 for the Company’s earnings per share calculation.

Commitments and Contingencies

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and costs can be reasonably estimated. See Note 15 for discussion of the Company’s commitments and contingencies.

Concentration of Risk

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

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

The Company operates a substantial portion of its oil and natural gas properties. As the operator of a property, the Company makes full payment for costs associated with the property and seeks reimbursement from the other working interest owners in the property for their share of those costs. The Company’s joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability of the joint interest partners to reimburse the Company could be adversely affected.

The purchasers of the Company’s oil, natural gas and NGL production consist primarily of independent marketers, major oil and natural gas companies and gas pipeline companies. See Note 23 for information regarding the Company’s major customers. The Company believes alternate purchasers are available in its areas of operations and does not believe the loss of any one purchaser would materially affect the Company’s ability to sell the oil, natural gas and NGLs it produces.

Recent Accounting Pronouncements

Recent Accounting Pronouncements. In April 2014, the financial accounting standards board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity”, which amends the definition of a discontinued operations to elevate the threshold for a disposal transaction to qualify as a discontinued operation and requires entities to provide additional disclosures for disposal transactions that do not meet the discontinued operations criteria. The guidance is effective prospectively for all disposals (except disposals classified as held for sale before the adoption date) or components initially classified as held for sale in periods beginning on or after December 15, 2014, with early adoption permitted. The guidance was adopted January 1, 2015 and had no impact for the year ended December 31, 2015.

In November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which requires the classification of all deferred tax assets and liabilities as non-current. The guidance is effective on either a prospective or retrospective basis for periods beginning after December 15, 2016, with early adoption permitted. The Company elected to adopt this guidance on a prospective basis on December 31, 2015, and as such, did not retrospectively adjust prior periods. Since the Company’s deferred tax assets and liabilities are equal and offsetting after including the effect of the valuation allowance, adoption of the guidance resulted in the elimination, for presentation purposes, of a non-current deferred tax asset and a current deferred tax liability on the accompanying consolidated balance sheet at December 31, 2015.

Recent Accounting Pronouncements Not Yet Adopted. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Certain of the provisions also amend or supersede existing guidance applicable to the recognition of a gain or loss on transfers of nonfinancial assets that are not an output of an entity’s ordinary activities, including sales of property, plant and equipment and real estate. In August, 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date," which defers the effective date of ASU 2014-09 to annual periods beginning after December 15, 2017, and interim periods within that reporting period. Early adoption is permitted, and either a full retrospective or modified approach may be used for adoption. The Company is currently evaluating the effect, if any, that the updated standard will have on its consolidated financial statements and related disclosures.

In August 2014, the FASB issued ASU 2014-15, “Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern,” which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The Company evaluated the effect of the guidance and it will have no impact on its related disclosures.

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

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

In February 2016, the FASB issued ASU 2016-02, “Leases (Topic 842),” which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

In March 2016, the FASB issued ASU 2016-06, “Contingent Put and Call Options in Debt Instruments” which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts, which is one of the criteria for bifurcating an embedded derivative. The amendments eliminate diversity in practice in assessing embedded contingent call (put) options in debt instruments. The guidance requires adoption by application of a modified retrospective approach to existing and future debt instruments effective for fiscal years after December 15, 2016, including interim periods within those years.  Early adoption is permitted. The Company is currently evaluating the effect that the guidance will have on its consolidated financial statements and related disclosures.

Fair Value Transfers

The Company recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Years Ended December 31,
	2015			2014			2013
	(In thousands)
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	(296,386	)	$	(235,793	)	$	(274,850	)
Cash (paid) received for income taxes	$	(88	)	$	1,928		$	(4,610	)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	$	—		$	—		$	(255,000	)
Change in accrued capital expenditures	$	177,586		$	(55,557	)	$	72,848
Equity issued for debt	$	(63,299	)	$	—		$	—
Preferred stock dividends paid in common stock	$	(16,188	)	$	—		$	—
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$	(50,310	)	$	—		$	—

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2015

Gulf Properties

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Disposal, Revenue and Expense Information

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 consolidated statements of operations for the years ended December 31, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2014(1)		2013
Revenues	$	90,920	$	627,236
Expenses	$	63,674	$	491,991

____________________

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

Permian Properties

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Disposal, Revenue and Expense Information

The following table presents revenues and direct operating expenses of the Permian Properties included in the accompanying consolidated statement of operations for the year ended December 31, 2013 (in thousands):

	Year Ended December 31, 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.

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Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2015

Variable Interest Entity [Line Items]

Royalty Trusts Distributions

The following distributions will be paid on February 26, 2016 to holders of record as of the close of business on February 12, 2016 (in thousands):

Royalty Trust	Total Distribution		Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I	$	8,708	$	6,367
Permian Trust	7,560		7,560
Mississippian Trust II	6,825		5,682
Total	$	23,093	$	19,609

Royalty Trusts

Variable Interest Entity [Line Items]

Schedule of Royalty Trust Units By Class

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

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

 ____________________

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

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

Royalty Trusts Ownership Interest

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

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

Royalty Trusts Distributions

Quarterly distributions declared and paid by the Royalty Trusts during the years ended December 31, 2015, 2014 and 2013 as follows (in thousands):

	Year Ended December 31,
	2015(1)		2014(2)		2013(3)
Total distributions	$	158,632	$	234,326	$	299,674
Distributions to third-party unitholders	$	138,305	$	193,807	$	206,470

____________________

(1) Subordination thresholds were not met for the Permian Trust and Mississippian Trust II’s distributions for the year ended December 31, 2015, resulting in reduced distributions to the Company on its subordinated units for this period.

(2) Subordination thresholds were not met for the Mississippian Trust I’s first or second quarter 2014 distributions, the Permian Trust’s second, third or fourth quarter 2014 distributions or for the Mississippian Trust II’s distributions for the year ended December 31, 2014, resulting in reduced distributions to the Company on its subordinated units for these periods.

(3) Subordination thresholds were not met for the Mississippian Trust I’s second, third or fourth quarter 2013 distributions, the Permian Trust’s second quarter 2013 distribution or for the Mississippian Trust II’s fourth quarter 2013 distribution, resulting in reduced distributions to the Company on its subordinated units for these periods.

Assets and Liabilities Included in Consolidated Balance Sheets

The Royalty Trusts’ assets and liabilities, after considering the effects of intercompany eliminations, included in the accompanying consolidated balance sheets at December 31, 2015 and 2014 consisted of the following (in thousands):

	December 31,
	2015			2014
Cash and cash equivalents(1)	$	7,824		$	9,387
Accounts receivable	4,457			17,660
Derivative contracts	—			6,589
Total current assets	12,281			33,636
Investment in royalty interests(2)	1,325,942			1,325,942
Less: accumulated depletion and impairment(3)	(1,248,957		)	(284,094		)
	76,985			1,041,848
Total assets	$	89,266		$	1,075,484
Accounts payable and accrued expenses	$	1,060		$	2,852
Total liabilities	$	1,060		$	2,852

____________________

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

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

(3) Includes cumulative full cost ceiling limitation impairment of $976.2 million and $42.3 million at December 31, 2015 and 2014, respectively.

Pinon Gathering Company LLC

Variable Interest Entity [Line Items]

Amounts Due To/From PGC

Amounts due from and due to PGC as of December 31, 2014 included in the accompanying consolidated balance sheet are as follows (in thousands):

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

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

Significant Unobservable Inputs - Derivative Contracts

The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of the Company’s natural gas basis swaps at December 31, 2015 and 2014 are included in the table below.

Unobservable Input	Range							Weighted Average			Fair Value
	(Price per Mcf)										(In thousands)
December 31, 2015
Natural gas basis differential forward curve	$	(0.06	)	–	$	(0.28	)	$	(0.22	)	$	(1,748	)
December 31, 2014
Natural gas basis differential forward curve	$	(0.03	)	–	$	(0.38	)	$	(0.29	)	$	350

Significant Unobservable Inputs - Liabilities

The significant unobservable inputs and range and weighted average of these inputs used in the fair value measurement of the conversion features atDecember 31, 2015are included in the table below.

Unobservable Input	Range					Weighted Average		Fair Value
								(In thousands)
December 31, 2015
Long-term debt conversion feature hazard rate	114.0	%	–	135.2	%	119.2	%	$	29,355

Assets and Liabilities Measured at Fair Value on Recurring Basis

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

December 31, 2015

	Fair Value Measurements						Netting(1)			Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	85,524	$	—	$	(1,175	)	$	84,349
Investments	10,106		—		—		—			10,106
	$	10,106	$	85,524	$	—	$	(1,175	)	$	94,455
Liabilities
Commodity derivative contracts	$	—	$	—	$	1,748	$	(1,175	)	$	573
Long-term debt holder conversion feature	—		—		29,355		—			29,355
Mandatory prepayment feature - PGC Senior Secured Notes	—		2,941		—		—			2,941
	$	—	$	2,941	$	31,103	$	(1,175	)	$	32,869

December 31, 2014

	Fair Value Measurements						Netting(1)		Assets/Liabilities at Fair Value
	Level 1		Level 2		Level 3
Assets
Commodity derivative contracts	$	—	$	338,067	$	350	$	—	$	338,417
Investments	11,106		—		—		—		11,106
	$	11,106	$	338,067	$	350	$	—	$	349,523
Liabilities
Guarantee	$	—	$	—	$	5,104	$	—	$	5,104
	$	—	$	—	$	5,104	$	—	$	5,104

____________________

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

Fair Value, Reconciliation of Level 3 Fair Value Measurements for Commodity Derivatives

The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for commodity derivative contracts during the years ended December 31, 2015, 2014 and 2013 (in thousands):

Level 3 Fair Value Measurements - Commodity Derivative Contracts	2015			2014		2013
Beginning balance	$	350		$	—	$	(512	)
Loss on commodity derivative contracts	(350		)	—		(133		)
Purchases	(1,748		)	350		—
Settlements paid	—			—		645
Level 3 commodity derivative contracts at December 31	$	(1,748	)	$	350	$	—

Fair Value, Reconciliation of Level 3 Fair Value Measurements - Liabilities

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

Level 3 Fair Value Measurements - Guarantee	2015			2014
Beginning balance	$	5,104		$	—
Issuances	—			9,446
Loss on guarantee	—			(4,342		)
Settlements	(5,104		)	—
Ending balance	$	—		$	5,104

The table below sets forth a reconciliation of the Company’s Level 3 fair value measurements for long-term debt holder conversion features during the year ended December 31, 2015 (in thousands):

Level 3 Fair Value Measurements - Long-Term Debt Holder Conversion Feature
Beginning balance	$	—
Issuances	31,200
Gain on derivative holder conversion feature	10,198
Conversions	(12,043		)
Ending balance	$	29,355

Estimated Fair Value and Carrying Value of Senior Notes

The estimated fair values and carrying values of the Company’s senior notes at December 31, 2015 and 2014 were as follows (in thousands):

	December 31, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
8.75% Senior Secured Notes due 2020(1)	$	403,098	$	1,301,098	$	—	$	—
Senior Unsecured Notes
8.75% Senior Notes due 2020(2)	$	39,740	$	392,666	$	303,750	$	445,402
7.5% Senior Notes due 2021(3)	$	79,812	$	759,711	$	752,000	$	1,178,486
8.125% Senior Notes due 2022	$	57,749	$	527,737	$	472,500	$	750,000
7.5% Senior Notes due 2023(4)	$	58,799	$	541,572	$	519,750	$	821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022(5)	$	44,199	$	82,294	$	—	$	—
7.5% Convertible Senior Notes due 2023(6)	$	15,125	$	26,428	$	—	$	—

___________________

(1) Carrying value includes mandatory prepayment feature liabilities with fair value of $2,941 and is net of $29,842 discount at December 31, 2015.

(2) Carrying value is net of $3,269 and $4,598 discount at December 31, 2015 and 2014, respectively.

(3) Carrying value includes a premium of $1,944 and $3,486 at December 31, 2015 and 2014, respectively.

(4) Carrying value is net of $1,989 and $3,452 discount at December 31, 2015 and 2014, respectively.

(5) Carrying value includes holder conversion feature liabilities with fair value of $21,874 and is net of $180,751 discount at December 31, 2015.

(6) Carrying value includes holder conversion feature liabilities with fair value of $7,481 and is net of $59,549 discount at December 31, 2015.

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Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2015

Receivables [Abstract]

Summary of Accounts Receivable

A summary of accounts receivable is as follows (in thousands):

	December 31,
	2015			2014
Oil, natural gas and NGL sales	$	61,140		$	139,848
Joint interest billing	60,403			170,937
Oil and natural gas services	2,417			21,436
Other	8,274			4,939
	132,234			337,160
Less: allowance for doubtful accounts	(4,847		)	(7,083		)
Total accounts receivable, net	$	127,387		$	330,077

Balance and Activity in Allowance for Doubtful Accounts

The following table presents the balance and activity in the allowance for doubtful accounts for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2015			2014			2013
Beginning balance	$	7,083		$	11,061		$	5,635
Additions charged to costs and expenses(1)	1,320			818			5,497
Deductions(2)	(3,556		)	(4,796		)	(71		)
Ending balance	$	4,847		$	7,083		$	11,061

____________________

(1) Includes $2.7 million of allowance for receivables deemed uncollectible at December 31, 2013, primarily due to the bankruptcy status of customers.

(2) Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Deductions in 2015 are primarily due to the write-off of receivables in conjunction with a lawsuit settlement, and deductions in 2014 are related to the sale of the Gulf Properties.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

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

	December 31,
	2015			2014
Oil and natural gas properties
Proved(1)	$	12,529,681		$	11,707,147
Unproved	363,149			290,596
Total oil and natural gas properties	12,892,830			11,997,743
Less accumulated depreciation, depletion and impairment	(11,149,888		)	(6,359,149		)
Net oil and natural gas properties capitalized costs	1,742,942			5,638,594
Land	14,260			16,300
Non-oil and natural gas equipment(2)	373,687			602,392
Buildings and structures(3)	227,673			263,191
Total	615,620			881,883
Less accumulated depreciation and amortization	(123,860		)	(305,420		)
Other property, plant and equipment, net	491,760			576,463
Total property, plant and equipment, net	$	2,234,702		$	6,215,057

____________________

(1) Includes cumulative capitalized interest of approximately $48.9 million and $38.1 million at December 31, 2015 and 2014, respectively.

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

(3) Includes cumulative capitalized interest of approximately $20.4 million and $17.1 million at December 31, 2015 and 2014, respectively.

Capitalized Costs of Unproved Properties Excluded from Amortization

The following table summarizes the costs, by year incurred, related to unproved properties and pipe inventory, which were excluded from oil and natural gas properties subject to amortization at December 31, 2015 (in thousands):

			Year Cost Incurred
	Total		2015		2014		2013		2012 and Prior
Property acquisition	$	362,803	$	197,849	$	70,304	$	14,011	$	80,639
Exploration(1)	34,988		10,698		6,263		17,688		339
Total costs incurred	$	397,791	$	208,547	$	76,567	$	31,699	$	80,978

____________________

(1) Includes $34.7 million of pipe inventory costs incurred ($10.5 million in 2015, $6.2 million in 2014 and $18.0 million in 2013 and prior years).

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Other Assets (Tables)

12 Months Ended

Dec. 31, 2015

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other Assets

Other assets consist of the following (in thousands):

	December 31,
	2015		2014
Debt issuance costs, net of amortization	$	72,259	$	56,445
Deferred tax asset(1)	—		95,843
Investments	10,106		11,106
Other	—		1,853
Total other assets	$	82,365	$	165,247

____________________

(1) The deferred tax asset at December 31, 2015, upon which there is a full valuation allowance, was netted against the deferred tax liability for presentation purposes as a result of the Company’s adoption of ASU 2015-17 in the fourth quarter of 2015. See Note 1.

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Accounts Payable and Accrued Expenses (Tables)

12 Months Ended

Dec. 31, 2015

Payables and Accruals [Abstract]

Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consist of the following (in thousands):

	December 31,
	2015		2014
Accounts payable and other accrued expenses	$	231,697	$	392,500
Accrued interest	73,320		79,704
Production payable	55,260		120,573
Payroll and benefits	42,728		44,496
Convertible perpetual preferred stock dividends	21,572		11,072
Drilling advances	2,295		33,195
Related party	1,545		1,852
Total accounts payable and accrued expenses	$	428,417	$	683,392

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Long-Term Debt

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

	December 31,
	2015		2014
Senior credit facility	$	—	$	—
8.75% Senior Secured Notes due 2020, including mandatory prepayment feature liabilities of $2,941, and net of $29,842 discount	1,301,098		—
Senior Unsecured Notes
8.75% Senior Notes due 2020, net of $3,269 and $4,598 discount, respectively	392,666		445,402
7.5% Senior Notes due 2021, including a premium of $1,944 and $3,486, respectively	759,711		1,178,486
8.125% Senior Notes due 2022	527,737		750,000
7.5% Senior Notes due 2023, net of $1,989 and $3,452 discount, respectively	541,572		821,548
Convertible Senior Unsecured Notes
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount	82,294		—
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount	26,428		—
Total debt	3,631,506		3,195,436
Less: current maturities of long-term debt	—		—
Long-term debt	$	3,631,506	$	3,195,436

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Offsetting Assets and Liabilities

The following tables summarize (i) the Company's commodity derivative contracts on a gross basis, (ii) the effects of netting assets and liabilities for which the right of offset exists based on master netting arrangements and (iii) for the Company’s net derivative liability positions, the applicable portion of shared collateral under the senior credit facility (in thousands):

December 31, 2015

	Gross Amounts		Gross Amounts Offset			Amounts Net of Offset		Financial Collateral			Net Amount
Assets
Derivative contracts - current	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	85,524	$	(1,175	)	$	84,349	$	—		$	84,349
Liabilities
Derivative contracts - current	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—
Derivative contracts - noncurrent	—		—			—		—			—
Total	$	1,748	$	(1,175	)	$	573	$	(573	)	$	—

December 31,2014

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

Open Oil and Natural Gas Commodity Derivative Contracts

At December 31, 2015, the Company’s open commodity derivative contracts consisted of the following:

Oil Price Swaps

	Notional (MBbls)	Weighted Average Fixed Price
January 2016 - December 2016	1,464	$	88.36

Natural Gas Basis Swaps

	Notional (MMcf)	Weighted Average Fixed Price
January 2016 - December 2016	10,980	$	(0.38	)

Oil Collars - Three-way

	Notional (MBbls)	Sold Put		Purchased Put		Sold Call
January 2016 - December 2016	2,556	$	83.14	$	90.00	$	100.85

Fair Value of Derivative Contracts

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

		December 31,
Type of Contract	Balance Sheet Classification	2015			2014
Derivative assets
Oil price swaps	Derivative contracts—current	$	68,224		$	204,072
Natural gas price swaps	Derivative contracts—current	—			29,648
Natural gas basis swaps	Derivative contracts—current	—			350
Oil collars—three way	Derivative contracts—current	17,300			56,289
Natural gas collars	Derivative contracts—current	—			1,055
Oil price swaps	Derivative contracts—noncurrent	—			36,288
Oil collars—three way	Derivative contracts—noncurrent	—			10,715
Derivative liabilities
Natural gas basis swaps	Derivative contracts—current	(1,748		)	—
Long-term debt holder conversion feature	Long-term debt	(29,355		)	—
Mandatory prepayment feature - PGC Senior Secured Notes	Long-term debt	(2,941		)	—
Total net derivative contracts		$	51,480		$	338,417

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations

The following table presents the balance and activity of the asset retirement obligations for the years ended December 31, 2015, 2014 and 2013 (in thousands).

	2015			2014			2013
Beginning balance	$	54,402		$	424,117		$	498,410
Liability incurred upon acquiring and drilling wells	1,662			4,968			5,078
Revisions in estimated cash flows(1)	44,060			(5,848		)	(3,077		)
Liability settled or disposed in current period(2)	(1,023		)	(377,927		)	(113,071		)
Accretion	4,477			9,092			36,777
Ending balance	103,578			54,402			424,117
Less: current portion	8,399			—			87,063
Asset retirement obligations, net of current	$	95,179		$	54,402		$	337,054

____________________

(1) Revisions for the year ended December 31, 2015 relate primarily to changes in estimated well lives.

(2) Liability settled or disposed for the year ended December 31, 2014, includes $366.0 million associated with the Gulf Properties sold in February 2014, as discussed in Note 3.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Future Minimum Rental Payments for Operating Leases

Future minimum payments under noncancelable operating leases (with initial lease terms exceeding one year) as of December 31, 2015 were as follows (in thousands):

Years ending December 31
2016	$	584
2017	555
2018	485
2019	72
2020	—
Thereafter	—
	$	1,696

Oil and Natural Gas Transportation and Throughput Obligations

The amounts of the required payments related to the transportation and throughput agreements as of December 31, 2015 were as follows (in thousands):

Years ending December 31
2016	$	14,082
2017	13,869
2018	14,163
2019	9,282
2020	1,584
Thereafter	11,088
	$	64,068

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Equity (Tables)

12 Months Ended

Dec. 31, 2015

Stockholders Equity Note [Line Items]

Preferred Stock Terms

The following table summarizes information about each series of the Company’s convertible perpetual preferred stock outstanding at December 31, 2015:

	Convertible Perpetual Preferred Stock
	8.5%		7.0%
Liquidation preference per share	$	100.00	$	100.00
Annual dividend per share	$	8.50	$	7.00
Conversion rate per share to common stock	12.4805		12.8791

Preferred Stock Dividends

Preferred stock dividend payments and accruals for the Company’s 8.5%, 7.0% and 6.0% convertible perpetual preferred stock for the years ended December 31, 2015, 2014 and 2013 are as follows:

	December 31,
	2015		2014		2013
	(In thousands)
8.5% Convertible perpetual preferred stock
Dividends paid in cash	$	11,262	$	22,525	$	22,525
Dividends satisfied in shares of common stock(1)	$	11,262	$	—	$	—
Accrued dividends at period end	$	8,447	$	8,447	$	8,447
7.0% Convertible perpetual preferred stock
Dividends paid in cash	$	—	$	21,000	$	21,000
Dividends satisfied in shares of common stock(2)	$	10,500	$	—	$	—
Accrued dividends at period end	$	13,125	$	2,625	$	2,625
Dividends in arrears(3)	$	10,500	$	—	$	—
6.0% Convertible perpetual preferred stock(4)
Dividends paid in cash	$	—	$	12,000	$	12,000
Accrued dividends at period end	$	—	$	—	$	5,500

____________________

(1) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 18.6 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending July 29, 2015. Based upon the common stock’s closing price on August 17, 2015, the common stock issued had a market value of approximately $9.5 million, ($3.58 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $1.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying condensed consolidated statement of operations.

(2) For the year ended December 31, 2015, the Company paid a semi-annual dividend by issuing approximately 5.7 million shares of common stock. For purposes of the dividend payment, the value of each share issued was calculated as 95% of the average volume-weighted share price for the 15 trading day period ending April 28, 2015. Based upon the common stock’s closing price on May 15, 2015, the common stock issued had a market value of approximately $6.7 million, ($2.23 per outstanding share at the time the dividend was paid) that resulted in a difference between the fixed rate semi-annual dividend and the value of shares issued of approximately $3.8 million, which was recorded as a reduction to preferred stock dividends in the accompanying condensed consolidated statement of operations.

(3) In the third quarter of 2015, the Company announced the suspension of payment of the semi-annual dividend on shares of its 7.0% convertible perpetual preferred stock.

(4) The final dividend payment for the 6.0% convertible preferred stock was made during 2014.

Treasury Stock Activity

The following table shows the number of shares withheld for taxes and the associated value of those shares for the years ended December 31, 2015, 2014 and 2013. These shares were accounted for as treasury stock when withheld, and then immediately retired.

	Year Ended December 31,
	2015		2014		2013
	(In thousands)
Number of shares withheld for taxes	1,872		1,034		5,679
Value of shares withheld for taxes	$	2,428	$	6,373	$	30,126

Preferred Stock

Stockholders Equity Note [Line Items]

Schedule of Stock by Class

The following table presents information regarding the Company’s preferred stock (in thousands):

	December 31,
	2015	2014
Shares authorized, $0.001 par value	50,000	50,000
Shares outstanding at end of period
8.5% Convertible perpetual preferred stock	2,650	2,650
7.0% Convertible perpetual preferred stock(1)	2,770	3,000

____________________

(1) For the year ended December 31, 2015, approximately 230,500 shares were converted into approximately 3.0 million shares of the Company’s common stock.

Common Stock

Stockholders Equity Note [Line Items]

Schedule of Stock by Class

The following table presents information regarding the Company’s common stock (in thousands):

	December 31,
	2015	2014
Shares authorized	1,800,000	800,000
Shares outstanding at end of period	633,471	484,819
Shares held in treasury	2,113	1,113

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Unvested Restricted Stock Awards

The following table presents a summary of the Company’s unvested restricted stock awards.

	Number of Shares		Weighted- Average Grant Date Fair Value
	(In thousands)
Unvested restricted shares outstanding at December 31, 2012	15,328		$	8.07
Granted	7,462		$	6.32
Vested	(13,395	)	$	7.85
Forfeited / Canceled	(1,752	)	$	7.33
Unvested restricted shares outstanding at December 31, 2013	7,643		$	6.92
Granted	6,367		$	6.17
Vested	(3,432	)	$	7.04
Forfeited / Canceled	(2,022	)	$	6.60
Unvested restricted shares outstanding at December 31, 2014	8,556		$	6.39
Granted	2,928		$	0.88
Vested	(5,186	)	$	4.95
Forfeited / Canceled	(672	)	$	6.38
Unvested restricted shares outstanding at December 31, 2015	5,626		$	4.85

Summary of Unvested Restricted Stock Units

The following table presents a summary of the Company’s unvested restricted stock units which may be settled in shares of the Company’s common stock, cash or some combination of common stock and cash at the Company’s election. These restricted stock units are liability-classified awards, which vest ratably over a maximum four-year period from the date of grant and were valued at December 31, 2015 based upon the Company’s period end common stock price.

	Number of Units		Fair Value per Unit at December 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	11,095
Vested(1)	(2,200	)
Forfeited / Canceled	(767	)
Unvested units outstanding at December 31, 2015	8,128		$	0.20

____________________

(1) Restricted stock units which vested during the year ended December 31, 2015 were settled by the issuance of common stock.

The restricted stock units were valued based upon the Company’s period end common stock price, discounted using a credit spread (10.6% at December 31, 2015) that was determined based upon an analysis of the historical option adjusted spread for the Company’s outstanding senior notes and the outstanding long-term debt of comparable companies.

	Number of Units		Fair Value per Unit at December 31, 2015
	(In thousands)
Unvested units outstanding at December 31, 2014	—
Granted	3,104
Vested	(979	)
Forfeited / Canceled	(122	)
Unvested units outstanding at December 31, 2015	2,003		$	0.04	-	$	0.20

Performance Units/Performance Share Units Fair Value Assumptions

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

	December 31,
	2015			2014
Volatility factor	120.0		%	55.6		%
Weighted-average risk-free interest rate	0.7		%	0.5		%
Weighted-average fair value per unit	$	1.08		$	13.85

The following table presents a summary of the fair values of the performance share units granted and the related assumptions for all outstanding performance share units at December 31, 2015.

	December 31, 2015
Volatility factor	95.3		%
Weighted-average risk-free interest rate	1.1		%
Weighted-average fair value per unit	$	0.10

Performance Units/Performance Share Units Outstanding Activity

Performance share unit activity for the year ended December 31, 2015 was as follows:

	Number of Performance Share Units
	(In thousands)
Outstanding at December 31, 2014	—
Granted	2,044
Forfeited /canceled	(151	)
Outstanding at December 31, 2015	1,893
Performance period ending December 31, 2017
Vested	695
Unvested	1,198

Performance unit activity for the years ended December 31, 2015, 2014 and 2013 was as follows (in thousands):

	December 31,
	2015		2014		2013(1)
Outstanding at January 1	66		31		—
Granted	—		47		31
Vested	(28	)	—		—
Forfeited /canceled	—		(12	)	—
Outstanding at December 31	38		66		31
Performance period ending December 31, 2015
Vested	—		9		12
Unvested	—		19		19
Performance period ending December 31, 2016
Vested	26		13		—
Unvested	12		25		—

____________________

(1)    The 2013 performance units fully vested on December 31, 2015, with no amounts paid.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

(Benefit) Provision for Income Taxes

The Company’s income tax provision (benefit) consisted of the following components for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Year Ended December 31,
	2015		2014			2013
Current
Federal	$	—	$	(1,160	)	$	3,842
State	123		(1,133		)	1,842
	123		(2,293		)	5,684
Deferred
Federal	—		—			—
State	—		—			—
	—		—			—
Total provision (benefit)	123		(2,293		)	5,684
Less: income tax provision attributable to noncontrolling interest	90		283			308
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	33	$	(2,576	)	$	5,376

Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate

A reconciliation of the provision (benefit) for income taxes at the statutory federal tax rate to the Company’s actual income tax benefit is as follows for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	2015			2014			2013
Computed at federal statutory rate	$	(1,512,325	)	$	122,362		$	(178,078	)
State taxes, net of federal benefit	(19,988		)	4,145			(886		)
Non-deductible expenses	816			1,895			2,589
Non-deductible debt costs	10,228			—			—
Stock-based compensation	6,700			1,467			7,611
Net effects of consolidating the non-controlling interests’ tax provisions	218,196			(34,614		)	(13,901		)
Change in valuation allowance	1,296,405			(96,769		)	188,599
Other	1			(1,062		)	(558		)
Total provision (benefit) attributable to SandRidge Energy, Inc.	$	33		$	(2,576	)	$	5,376

Deferred Tax Assets and Liabilities

Significant components of the Company’s deferred tax assets and liabilities are as follows (in thousands):

	December 31,
	2015			2014
Deferred tax liabilities
Investments(1)	$	138,310		$	272,902
Property, plant and equipment	—			364,576
Derivative contracts	30,989			113,735
Long-term debt	10,017			—
Total deferred tax liabilities	179,316			751,213
Deferred tax assets
Property, plant and equipment	807,275			—
Allowance for doubtful accounts	18,702			19,086
Net operating loss carryforwards	1,190,799			1,265,458
Compensation and benefits	18,607			19,867
Alternative minimum tax credits and other carryforwards	44,302			43,840
Asset retirement obligations	38,314			21,946
CO2 under-delivery shortfall penalty	40,654			27,674
Other	4,305			2,934
Total deferred tax assets	2,162,958			1,400,805
Valuation allowance	(1,983,642		)	(649,592		)
Net deferred tax liability	$	—		$	—

____________________

(1) Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. See Note 4 for further discussion of the Royalty Trusts.

Unrecognized Tax Benefits

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

	December 31,
	2015		2014
Unrecognized tax benefit at January 1	$	77	$	1,382
Changes to unrecognized tax benefits related to a prior year	4		(17		)
Decreases to unrecognized tax benefits for settlements with tax authorities	—		(1,288		)
Unrecognized tax benefit at December 31	$	81	$	77

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(Loss) Earnings per Share (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share

The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings per share, for the years ended December 31, 2015, 2014 and 2013 (in thousands):

	Net (Loss) Income			Weighted Average Shares	(Loss) Earnings Per Share
	(In thousands, except per share amounts)
Year Ended December 31, 2015
Basic loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Effect of dilutive securities
Restricted stock and units(1)	—			—
Convertible preferred stock(2)	—			—
Convertible senior unsecured notes(3)	—			—
Diluted loss per share	$	(3,735,495	)	521,936	$	(7.16	)
Year Ended December 31, 2014
Basic earnings per share	$	203,260		479,644	$	0.42
Effect of dilutive securities
Restricted stock	—			2,181
Convertible preferred stock(2)	6,500			17,918
Diluted earnings per share	$	209,760		499,743	$	0.42
Year Ended December 31, 2013
Basic loss per share	$	(609,414	)	481,148	$	(1.27	)
Effect of dilutive securities
Restricted stock(4)	—			—
Convertible preferred stock(5)	—			—
Diluted loss per share	$	(609,414	)	481,148	$	(1.27	)

____________________

(1) No incremental shares of potentially dilutive restricted stock awards or units were included for the year ended December 31, 2015 as their effect was antidilutive under the treasury stock method.

(2) Potential common shares related to the Company’s outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.2 million and 71.7 million shares for the years ended December 31, 2015 and 2014, respectively, were excluded from the computation of (loss) earnings per share because their effect would have been antidilutive under the if-converted method.

(3) Potential common shares related to the Company’s outstanding 8.125% and 7.5% Convertible Senior Unsecured Notes covering 48.5 million shares for the year ended December 31, 2015 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

(4) Restricted stock awards covering 0.5 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.

(5) Potential common shares related to the Company’s outstanding 8.5%, 6.0% and 7.0% convertible perpetual preferred stock covering 90.1 million shares for the year ended December 31, 2013 were excluded from the computation of loss per share because their effect would have been antidilutive under the if-converted method.

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Subsequent Events (Tables)

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

Royalty Trust Distributions

The following distributions will be paid on February 26, 2016 to holders of record as of the close of business on February 12, 2016 (in thousands):

Royalty Trust	Total Distribution		Amount to be Distributed to Third-Party Unitholders
Mississippian Trust I	$	8,708	$	6,367
Permian Trust	7,560		7,560
Mississippian Trust II	6,825		5,682
Total	$	23,093	$	19,609

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Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Summarized Financial Information Concerning Segments

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(3)			All Other(4)			Consolidated Total
Year Ended December 31, 2015
Revenues	$	707,446		$	67,358		$	81,083		$	5,342		$	861,229
Inter-segment revenue	(12		)	(45,234		)	(47,274		)	—			(92,520		)
Total revenues	$	707,434		$	22,124		$	33,809		$	5,342		$	768,709
Loss from operations	$	(4,461,907	)	$	(59,999	)	$	(15,218	)	$	(105,554	)	$	(4,642,678	)
Interest expense, net	(42		)	—			—			(321,379		)	(321,421		)
Gain on extinguishment of debt	—			—			—			641,131			641,131
Other income, net	1,368			13			253			406			2,040
Loss before income taxes	$	(4,460,581	)	$	(59,986	)	$	(14,965	)	$	214,604		$	(4,320,928	)
Capital expenditures(5)	$	656,022		$	4,632		$	21,556		$	19,405		$	701,615
Depreciation, depletion, amortization and accretion	$	324,471		$	17,438		$	11,742		$	18,121		$	371,772
At December 31, 2015
Total assets	$	1,959,975		$	27,621		$	254,212		$	749,347		$	2,991,155
Year Ended December 31, 2014
Revenues	$	1,423,073		$	192,944		$	142,987		$	4,376		$	1,763,380
Inter-segment revenue	(173		)	(116,856		)	(87,593		)	—			(204,622		)
Total revenues	$	1,422,900		$	76,088		$	55,394		$	4,376		$	1,558,758
Income (loss) from operations	$	713,716		$	(37,564	)	$	(9,094	)	$	(76,834	)	$	590,224
Interest income (expense), net	100			—			—			(244,209		)	(244,109		)
Other (expense) income, net	(423		)	(541		)	9			4,445			3,490
Income (loss) before income taxes	$	713,393		$	(38,105	)	$	(9,085	)	$	(316,598	)	$	349,605
Capital expenditures(5)	$	1,508,100		$	18,385		$	44,606		$	37,798		$	1,608,889
Depreciation, depletion, amortization and accretion	$	443,573		$	29,105		$	10,085		$	20,260		$	503,023
At December 31, 2014
Total assets	$	6,273,802		$	115,083		$	219,691		$	650,649		$	7,259,225
Year Ended December 31, 2013
Revenues	$	1,834,480		$	187,456		$	179,989		$	3,127		$	2,205,052
Inter-segment revenue	(320		)	(120,815		)	(100,529		)	—			(221,664		)
Total revenues	$	1,834,160		$	66,641		$	79,460		$	3,127		$	1,983,388
Income (loss) from operations	$	62,509		$	(40,155	)	$	(21,567	)	$	(169,788	)	$	(169,001	)
Interest income (expense), net	1,168			—			(209		)	(271,193		)	(270,234		)
Loss on extinguishment of debt	—			—			—			(82,005		)	(82,005		)
Other income (expense), net	5,487			—			(3,222		)	10,180			12,445
Income (loss) before income taxes	$	69,164		$	(40,155	)	$	(24,998	)	$	(512,806	)	$	(508,795	)
Capital expenditures(5)	$	1,319,012		$	7,125		$	55,706		$	42,040		$	1,423,883
Depreciation, depletion, amortization and accretion	$	605,242		$	33,291		$	7,972		$	20,140		$	666,645

____________________

(1) (Loss) income from operations includes full cost ceiling limitation impairments of $4.5 billion and $164.8 million for the years ended December 31, 2015 and 2014, respectively, a loss on the sale of the Permian Properties of $398.9 million for the year ended December 31, 2013 and the Company’s (gain) loss on derivative contracts, including net cash payments upon settlement, for the years ended December 31, 2015, 2014 and 2013. See Note 13 for discussion of derivative contracts.

(2) For the years ended December 31, 2015, 2014 and 2013, (loss) income from operations includes impairments of $37.6 million, $27.4 million, and $11.1 million, respectively, on certain drilling assets.

(3) For the years ended December 31, 2015, 2014 and 2013, (loss) income from operations includes impairments of other midstream assets and the Company’s gas treating plants in west Texas of $7.1 million, $0.6 million and $3.9 million, respectively.

(4) (Loss) income from operations for the year ended December 31, 2015 includes an impairment of $15.4 million on property located in downtown Oklahoma City, Oklahoma and $0.7 million on gathering and compression equipment. See Note 7. For the year ended December 31, 2013, (loss) income from operations includes a $2.9 million impairment of a corporate asset and an $8.3 million impairment of the Company’s CO₂ compression facilities.

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

Major Customers

Major Customers. For the years ended December 31, 2015, 2014 and 2013, the Company had sales exceeding 10% of total revenues to the following oil and natural gas purchasers (in thousands):

	2015
	Sales		% of Revenue
Plains Marketing, L.P.	$	318,018	41.4	%
Targa Pipeline Mid-Continent West OK LLC	$	231,649	30.1	%

	2014
	Sales		% of Revenue
Plains Marketing, L.P.	$	597,117	38.3	%
Targa Pipeline Mid-Continent West OK LLC	$	333,027	21.4	%

	2013
	Sales		% of Revenue
Plains Marketing, L.P.	$	491,258	24.8	%
Shell Trading (US) Company	$	347,422	17.5	%
Targa Pipeline Mid-Continent West OK LLC	$	211,838	10.7	%

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Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2015

Condensed Consolidating Financial Statements Disclosure [Abstract]

Condensed Consolidating Balance Sheets of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors

Condensed Consolidating Balance Sheets

	December 31, 2015
	Parent			Guarantors		Non-Guarantors		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	426,917		$	847	$	7,824	$	—		$	435,588
Accounts receivable, net	—			122,606		4,781		—			127,387
Intercompany accounts receivable	1,226,994			1,305,573		30,683		(2,563,250		)	—
Derivative contracts	—			84,349		—		—			84,349
Prepaid expenses	—			6,826		7		—			6,833
Other current assets	—			19,931		—		—			19,931
Total current assets	1,653,911			1,540,132		43,295		(2,563,250		)	674,088
Property, plant and equipment, net	—			2,124,532		110,170		—			2,234,702
Investment in subsidiaries	2,749,514			8,531		—		(2,758,045		)	—
Other assets	72,259			16,008		—		(5,902		)	82,365
Total assets	$	4,475,684		$	3,689,203	$	153,465	$	(5,327,197	)	$	2,991,155
LIABILITIES AND STOCKHOLDERS’ (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued expenses	$	160,122		$	265,767	$	2,528	$	—		$	428,417
Intercompany accounts payable	1,337,688			1,192,569		32,993		(2,563,250		)	—
Derivative contracts	—			573		—		—			573
Asset retirement obligations	—			8,399		—		—			8,399
Total current liabilities	1,497,810			1,467,308		35,521		(2,563,250		)	437,389
Investment in subsidiaries	1,038,303			400,771		—		(1,439,074		)	—
Long-term debt	3,637,408			—		—		(5,902		)	3,631,506
Asset retirement obligations	—			95,179		—		—			95,179
Other long-term obligations	80			14,734		—		—			14,814
Total liabilities	6,173,601			1,977,992		35,521		(4,008,226		)	4,178,888
Stockholders’ (Deficit) Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,697,917		)	1,711,211		117,944		(1,829,155		)	(1,697,917		)
Noncontrolling interest	—			—		—		510,184			510,184
Total stockholders’ (deficit) equity	(1,697,917		)	1,711,211		117,944		(1,318,971		)	(1,187,733		)
Total liabilities and stockholders’ (deficit) equity	$	4,475,684		$	3,689,203	$	153,465	$	(5,327,197	)	$	2,991,155

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

____________________

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

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

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

Condensed Consolidating Statements of Operations of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors

Condensed Consolidating Statements of Operations

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2015
Total revenues	$	—		$	682,778		$	85,939		$	(8	)	$	768,709
Expenses
Direct operating expenses	—			364,483			10,879			(8		)	375,354
General and administrative	213			145,796			4,157			—			150,166
Depreciation, depletion, amortization and accretion	—			339,647			32,125			—			371,772
Impairment	—			3,599,810			934,879			—			4,534,689
Gain on derivative contracts	—			(65,049		)	(8,012		)	—			(73,061		)
Loss on settlement of contract	—			50,976			—			—			50,976
Loss (gain) on sale of assets	—			2,217			(726		)	—			1,491
Total expenses	213			4,437,880			973,302			(8		)	5,411,387
Loss from operations	(213		)	(3,755,102		)	(887,363		)	—			(4,642,678		)
Equity earnings from subsidiaries	(4,017,082		)	(263,847		)	—			4,280,929			—
Interest expense, net	(321,378		)	(43		)	—			—			(321,421		)
Gain on extinguishment of debt	641,131			—			—			—			641,131
Other income, net	—			1,910			130			—			2,040
Loss before income taxes	(3,697,542		)	(4,017,082		)	(887,233		)	4,280,929			(4,320,928		)
Income tax expense	3			—			120			—			123
Net loss	(3,697,545		)	(4,017,082		)	(887,353		)	4,280,929			(4,321,051		)
Less: net loss attributable to noncontrolling interest	—			—			—			(623,506		)	(623,506		)
Net loss attributable to SandRidge Energy, Inc.	$	(3,697,545	)	$	(4,017,082	)	$	(887,353	)	$	4,904,435		$	(3,697,545	)

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2014
Total revenues	$	—		$	1,341,531		$	217,367		$	(140	)	$	1,558,758
Expenses
Direct operating expenses	—			467,175			16,854			(140		)	483,889
General and administrative	331			118,249			4,285			—			122,865
Depreciation, depletion, amortization and accretion	—			446,149			56,874			—			503,023
Impairment	—			150,125			42,643			—			192,768
Gain on derivative contracts	—			(292,733		)	(41,278		)	—			(334,011		)
Total expenses	331			888,965			79,378			(140		)	968,534
(Loss) income from operations	(331		)	452,566			137,989			—			590,224
Equity earnings from subsidiaries	495,154			38,967			—			(534,121		)	—
Interest (expense) income, net	(244,209		)	100			—			—			(244,109		)
Other income (expense), net	—			3,521			(31		)	—			3,490
Income before income taxes	250,614			495,154			137,958			(534,121		)	349,605
Income tax (benefit) expense	(2,671		)	—			378			—			(2,293		)
Net income	253,285			495,154			137,580			(534,121		)	351,898
Less: net income attributable to noncontrolling interest	—			—			—			98,613			98,613
Net income attributable to SandRidge Energy, Inc.	$	253,285		$	495,154		$	137,580		$	(632,734	)	$	253,285

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Total revenues	$	—		$	1,675,481		$	308,300		$	(393	)	$	1,983,388
Expenses
Direct operating expenses	—			654,080			29,143			(393		)	682,830
General and administrative	329			323,808			6,288			—			330,425
Depreciation, depletion, amortization and accretion	—			581,435			85,210			—			666,645
Impairment	—			15,038			11,242			—			26,280
Loss on derivative contracts	—			24,702			22,421			—			47,123
Loss on sale of assets	—			291,743			107,343			—			399,086
Total expenses	329			1,890,806			261,647			(393		)	2,152,389
(Loss) income from operations	(329		)	(215,325		)	46,653			—			(169,001		)
Equity earnings from subsidiaries	(195,118		)	3,075			—			192,043			—
Interest (expense) income, net	(271,193		)	959			—			—			(270,234		)
Loss on extinguishment of debt	(82,005		)	—			—			—			(82,005		)
Other income (expense), net	—			16,173			(3,728		)	—			12,445
(Loss) income before income taxes	(548,645		)	(195,118		)	42,925			192,043			(508,795		)
Income tax expense	5,244			—			440			—			5,684
Net (loss) income	(553,889		)	(195,118		)	42,485			192,043			(514,479		)
Less: net income attributable to noncontrolling interest	—			—			—			39,410			39,410
Net (loss) income attributable to SandRidge Energy, Inc.	$	(553,889	)	$	(195,118	)	$	42,485		$	152,633		$	(553,889	)

Condensed Consolidating Statements of Cash Flows of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors

Condensed Consolidating Statements of Cash Flows

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2015
Net cash (used in) provided by operating activities	$	(326,674	)	$	524,313		$	124,626		$	51,272		$	373,537
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(879,201		)	—			—			(879,201		)
Acquisition of assets	—			(216,943		)	—			—			(216,943		)
Other	—			74,140			907			(18,543		)	56,504
Net cash (used in) provided by investing activities	—			(1,022,004		)	907			(18,543		)	(1,039,640		)
Cash flows from financing activities
Proceeds from borrowings	2,065,000			—			—			—			2,065,000
Repayments of borrowings	(939,466		)	—			—			—			(939,466		)
Distributions to unitholders	—			—			(158,629		)	20,324			(138,305		)
Intercompany (advances) borrowings, net	(475,618		)	497,140			(21,522		)	—			—
Other	(66,793		)	—			53,055			(53,053		)	(66,791		)
Net cash provided by (used in) financing activities	583,123			497,140			(127,096		)	(32,729		)	920,438
Net increase (decrease) in cash and cash equivalents	256,449			(551		)	(1,563		)	—			254,335
Cash and cash equivalents at beginning of year	170,468			1,398			9,387			—			181,253
Cash and cash equivalents at end of year	$	426,917		$	847		$	7,824		$	—		$	435,588

	Parent(1)			Guarantors(1)(2)			Non-Guarantors			Eliminations(2)			Consolidated
	(In thousands)
Year Ended December 31, 2014
Net cash (used in) provided by operating activities	$	(240,932	)	$	641,181		$	212,427		$	8,438		$	621,114
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(1,553,332		)	—			—			(1,553,332		)
Proceeds from sale of assets	—			711,728			2,747			—			714,475
Other	—			28,256			1,140			(47,780		)	(18,384		)
Net cash (used in) provided by investing activities	—			(813,348		)	3,887			(47,780		)	(857,241		)
Cash flows from financing activities
Distributions to unitholders	—			—			(234,327		)	40,520			(193,807		)
Repurchase of common stock	(111,827		)	—			—			—			(111,827		)
Intercompany (advances) borrowings, net	(215,368		)	215,373			(5		)	—			—
Other	(66,910		)	(42,821		)	19,260			(1,178		)	(91,649		)
Net cash (used in) provided by financing activities	(394,105		)	172,552			(215,072		)	39,342			(397,283		)
Net (decrease) increase in cash and cash equivalents	(635,037		)	385			1,242			—			(633,410		)
Cash and cash equivalents at beginning of year	805,505			1,013			8,145			—			814,663
Cash and cash equivalents at end of year	$	170,468		$	1,398		$	9,387		$	—		$	181,253

____________________

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

(2) Other investing activities for the Guarantor has increased to correctly exclude $193.8 million in noncontrolling interest distributions, with a corresponding decrease for Eliminations for this same line item. In addition, other financing activities for the Guarantor, has decreased to correctly exclude $193.8 million of noncontrolling interest distributions, with a corresponding increase for Eliminations for the same line item. The corrections did not result in any changes to consolidated net cash (used in) provided by investing activities or net cash used in financing activities.

	Parent			Guarantors			Non-Guarantors			Eliminations			Consolidated
	(In thousands)
Year Ended December 31, 2013
Net cash (used in) provided by operating activities	$	(239,026	)	$	852,026		$	254,723		$	907		$	868,630
Cash flows from investing activities
Capital expenditures for property, plant and equipment	—			(1,496,731		)	—			—			(1,496,731		)
Proceeds from sale of assets	—			2,566,742			17,373			—			2,584,115
Other	—			89,606			3,197			(109,831		)	(17,028		)
Net cash used in investing activities	—			1,159,617			20,570			(109,831		)	1,070,356
Cash flows from financing activities
Repayments of borrowings	(1,115,500		)	—			—			—			(1,115,500		)
Premium on debt redemption	(61,997		)	—			—			—			(61,997		)
Distributions to unitholders	—			—			(299,675		)	93,205			(206,470		)
Dividends paid—preferred	(55,525		)	—			—			—			(55,525		)
Intercompany borrowings (advances) , net	2,009,146			(2,018,212		)	9,066			—			—
Other	(31,821		)	6,660			14,845			15,719			5,403
Net cash provided by (used in) financing activities	744,303			(2,011,552		)	(275,764		)	108,924			(1,434,089		)
Net increase (decrease) in cash and cash equivalents	505,277			91			(471		)	—			504,897
Cash and cash equivalents at beginning of year	300,228			922			8,616			—			309,766
Cash and cash equivalents at end of year	$	805,505		$	1,013		$	8,145		$	—		$	814,663

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Supplemental Information on Oil and Natural Gas Producing Activities (Tables)

12 Months Ended

Dec. 31, 2015

Reserve Quantities [Line Items]

Capitalized Costs Relating to Oil, Natural Gas and NGL Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):

	December 31,
	2015			2014			2013
Oil and natural gas properties
Proved	$	12,529,681		$	11,707,147		$	10,972,816
Unproved	363,149			290,596			531,606
Total oil and natural gas properties	12,892,830			11,997,743			11,504,422
Less accumulated depreciation, depletion and impairment	(11,149,888		)	(6,359,149		)	(5,762,969		)
Net oil and natural gas properties capitalized costs	$	1,742,942		$	5,638,594		$	5,741,453

Cost Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):

	Year Ended December 31,
	2015		2014		2013
Acquisitions of properties
Proved	$	35,376	$	73,370	$	21,130
Unproved	210,065		123,649		100,242
Exploration(1)	29,297		41,070		82,775
Development	571,562		1,288,395		1,131,269
Total cost incurred	$	846,300	$	1,526,484	$	1,335,416

____________________

(1) Includes seismic costs of $7.1 million, $10.8 million and $6.7 million for 2015, 2014 and 2013, respectively.

Results of Operations for Oil, Natural Gas and NGL Producing Activities

The Company’s results of operations from oil and natural gas producing activities for each of the years 2015, 2014 and 2013 are shown in the following table (in thousands):

	Year Ended December 31,
	2015			2014(1)			2013
Revenues	$	707,434		$	1,420,879		$	1,820,278
Expenses
Production costs	324,141			377,819			548,719
Depreciation and depletion	319,913			434,295			567,732
Accretion of asset retirement obligations	4,477			9,092			36,777
Impairment	4,473,787			164,779			—
Total expenses	5,122,318			985,985			1,153,228
(Loss) income before income taxes	(4,414,884		)	434,894			667,050
Income tax expense (benefit)(2)	126			(2,852		)	(7,471		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	(4,415,010	)	$	437,746		$	674,521

____________________

(1) Total expenses increased by $164.8 million and benefit of income taxes decreased by $1.1 million to correctly include the impact of the ceiling test impairment incurred during the year ended December 31, 2014.

(2) Reflects the Company’s effective tax rate for each period.

Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves

The summary below presents changes in the Company’s estimated reserves for 2013, 2014 and 2015.

	Oil		NGL		Natural Gas
	(MBbls)		(MBbls)		(MMcf)(1)
Proved developed and undeveloped reserves
As of December 31, 2012	262,045		67,994		1,415,042
Revisions of previous estimates	(13,969	)	3,717		(53,432	)
Acquisitions of new reserves	43		13		363
Extensions and discoveries	40,570		18,686		359,918
Sales of reserves in place	(131,769	)	(29,067	)	(228,229	)
Production	(14,279	)	(2,291	)	(103,233	)
As of December 31, 2013(2)	142,641		59,052		1,390,429
Revisions of previous estimates	(18,687	)	11,103		167,589
Acquisitions of new reserves	1,009		441		12,527
Extensions and discoveries	37,603		27,500		467,185
Sales of reserves in place	(25,659	)	(2,516	)	(163,800	)
Production	(10,876	)	(3,794	)	(85,697	)
As of December 31, 2014(2)	126,031		91,786		1,788,233
Revisions of previous estimates	(70,708	)	(37,384	)	(759,106	)
Acquisitions of new reserves	22,447		2,460		15,952
Extensions and discoveries	9,741		9,257		160,865
Production	(9,600	)	(5,044	)	(92,104	)
As of December 31, 2015(2)	77,911		61,075		1,113,840
Proved developed reserves
As of December 31, 2012	136,605		33,785		896,701
As of December 31, 2013	83,893		35,807		951,609
As of December 31, 2014	79,022		56,823		1,203,447
As of December 31, 2015	48,639		51,089		964,617
Proved undeveloped reserves
As of December 31, 2012	125,440		34,209		518,341
As of December 31, 2013	58,748		23,245		438,820
As of December 31, 2014	47,009		34,963		584,786
As of December 31, 2015	29,272		9,986		149,223

____________________

(1) Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.

(2) Includes proved reserves attributable to noncontrolling interests at December 31, 2015, 2014 and 2013 as shown in the table below:

	December 31,
	2015	2014	2013
Oil (MBbl)	7,004	11,027	13,569
NGL (MBbl)	3,694	4,761	4,737
Natural gas (MMcf)	50,508	70,833	69,693

Calculation of Weighted Average Per Unit Prices

The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:

	At December 31,
	2015		2014		2013
Oil (per barrel)	$	45.29	$	91.65	$	95.67
NGL (per barrel)	$	12.68	$	32.79	$	31.40
Natural gas (per Mcf)	$	1.87	$	3.61	$	3.65

Standardized Measure of Discounted Future Cash Flows

The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).

	At December 31,
	2015			2014			2013
Future cash inflows from production	$	6,387,944		$	21,022,320		$	19,937,484
Future production costs	(2,731,542		)	(6,499,366		)	(6,843,713		)
Future development costs(1)	(838,945		)	(1,810,201		)	(2,546,680		)
Future income tax expenses	(901		)	(3,223,740		)	(2,283,541		)
Undiscounted future net cash flows	2,816,556			9,489,013			8,263,550
10% annual discount	(1,501,994		)	(5,401,261		)	(4,245,939		)
Standardized measure of discounted future net cash flows(2)	$	1,314,562		$	4,087,752		$	4,017,611

____________________

(1) Includes abandonment costs.

(2) Includes approximately $224.6 million, $643.3 million and $781.6 million attributable to noncontrolling interests at December 31, 2015, 2014 and 2013 respectively.

Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):

Present value as of December 31, 2012	$	5,840,368
Changes during the year
Revenues less production and other costs	(1,271,559		)
Net changes in prices, production and other costs	271,566
Development costs incurred	474,275
Net changes in future development costs	(207,729		)
Extensions and discoveries	1,406,102
Revisions of previous quantity estimates	(296,418		)
Accretion of discount	711,385
Net change in income taxes	477,328
Purchases of reserves in-place	1,628
Sales of reserves in-place	(3,172,187		)
Timing differences and other(1)	(217,148		)
Net change for the year	(1,822,757		)
Present value as of December 31, 2013(2)	4,017,611
Changes during the year
Revenues less production and other costs	(1,043,060		)
Net changes in prices, production and other costs	331,694
Development costs incurred	364,262
Net changes in future development costs	(341,183		)
Extensions and discoveries	1,785,963
Revisions of previous quantity estimates	(77,688		)
Accretion of discount	477,458
Net change in income taxes	(256,371		)
Purchases of reserves in-place	50,958
Sales of reserves in-place	(1,058,330		)
Timing differences and other(1)	(163,562		)
Net change for the year	70,141
Present value as of December 31, 2014(2)	4,087,752
Changes during the year
Revenues less production and other costs	(383,293		)
Net changes in prices, production and other costs	(3,813,465		)
Development costs incurred	217,596
Net changes in future development costs	273,437
Extensions and discoveries	230,055
Revisions of previous quantity estimates	(1,354,778		)
Accretion of discount	512,483
Net change in income taxes	1,426,333
Purchases of reserves in-place	18,429
Sales of reserves in-place	—
Timing differences and other(1)	100,013
Net change for the year	(2,773,190		)
Present value as of December 31, 2015(2)	$	1,314,562

____________________

(1) The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2) Includes approximately $224.6 million, $643.3 million and $781.6 million attributable to noncontrolling interests at December 31, 2015, 2014, and 2013 respectively.

Noncontrolling Interest

Reserve Quantities [Line Items]

Summary of Changes in Estimated Oil, Natural Gas and NGL Reserves

Includes proved reserves attributable to noncontrolling interests at December 31, 2015, 2014 and 2013 as shown in the table below:

	December 31,
	2015	2014	2013
Oil (MBbl)	7,004	11,027	13,569
NGL (MBbl)	3,694	4,761	4,737
Natural gas (MMcf)	50,508	70,833	69,693

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Quarterly Financial Results (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Information Disclosure [Abstract]

Quarterly Financial Results (Unaudited)

The Company’s operating results for each quarter of 2015 and 2014 are summarized below (in thousands, except per share data).

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2015
Total revenues	$	215,308		$	229,607		$	180,152		$	143,642
Loss from operations(1)(2)	$	(1,088,456	)	$	(1,535,083	)	$	(1,059,733	)	$	(959,406	)
Net loss(1)(2)	$	(1,151,874	)	$	(1,588,731	)	$	(796,485	)	$	(783,961	)
Loss applicable to SandRidge Energy, Inc. common stockholders(1)(2)	$	(1,045,834	)	$	(1,375,556	)	$	(649,526	)	$	(664,579	)
Loss applicable per share to SandRidge Energy, Inc. common stockholders(3)
Basic	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
Diluted	$	(2.19	)	$	(2.78	)	$	(1.23	)	$	(1.13	)
2014
Total revenues	$	443,056		$	374,714		$	394,107		$	346,881
(Loss) income from operations(4)(5)	$	(82,330	)	$	42,079		$	256,491		$	373,984
Net (loss) income(4)(5)	$	(142,406	)	$	(17,252	)	$	197,499		$	314,057
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders(4)(5)	$	(150,217	)	$	(46,775	)	$	145,957		$	254,295
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders(3)
Basic	$	(0.31	)	$	(0.10	)	$	0.30		$	0.55
Diluted	$	(0.31	)	$	(0.10	)	$	0.27		$	0.48

____________________

(1) Includes impairment of $1.1 billion, $1.5 billion, $1.1 billion and $886.8 million for the first, second, third and fourth quarters, respectively. See Note 8 for further discussion of impairment.

(2) Includes (gain) loss on derivative contracts of $(49.8) million, $33.0 million, $(42.2) million and $(14.0) million for the first, second, third and fourth quarters, respectively.

(3) (Loss applicable) income available per share to common stockholders for each quarter is computed using the weighted-average number of shares outstanding during the quarter, while earnings per share for the fiscal year is computed using the weighted-average number of shares outstanding during the year. Thus, the sum of (loss applicable) income available per share to common stockholders for each of the four quarters may not equal the fiscal year amount.

(4) Includes a full cost ceiling limitation impairment of $164.8 million in the first quarter and impairments of drilling assets of $3.1 million and $24.3 million in the second and fourth quarters, respectively.

(5) Includes loss (gain) on derivative contracts of $42.5 million, $85.3 million, $(132.6) million and $(329.2) million for the first, second, third and fourth quarters, respectively.

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Summary of Significant Accounting Policies - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 21, 2016	Mar. 11, 2016	Oct. 31, 2015	Aug. 31, 2015	Jun. 30, 2015	Jun. 09, 2015
Significant Accounting Policies [Line Items]
Debt instrument, subjective acceleration clause, period	30 days
Capitalized costs	$ 846,300	$ 1,526,484	$ 1,335,416
Maximum reserves sold from cost center not expected to result in significant alteration (less than)	25.00%
Natural gas balancing liability	$ 1,500	1,400
Advertising and promotional costs	700	1,300	5,100
Internal Costs
Significant Accounting Policies [Line Items]
Capitalized costs	$ 45,100	55,400	74,700
Buildings | Minimum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	10 years
Buildings | Maximum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	39 years
Equipment | Minimum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	3 years
Equipment | Maximum
Significant Accounting Policies [Line Items]
Property, plant and equipment, useful life	30 years
Oil And Gas Unproved Properties
Significant Accounting Policies [Line Items]
Interest capitalized during period	$ 10,800	14,700	11,700
Midstream And Corporate Assets
Significant Accounting Policies [Line Items]
Interest capitalized during period	$ 3,300	$ 5,000	$ 4,900
8.125% Convertible Senior Notes due 2022
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	8.125%
7.5% Convertible Senior Notes due 2023
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	7.50%
Senior credit facility
Significant Accounting Policies [Line Items]
Line of credit facility, current borrowing capacity									$ 900,000
Secured Debt | 8.75% Senior Secured Notes Due 2020
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	8.75%							8.75%
Convertible Debt | 8.125% Convertible Senior Notes due 2022
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	8.125%	8.125%				8.125%	8.125%
Convertible Debt | 7.5% Convertible Senior Notes due 2023
Significant Accounting Policies [Line Items]
Long-term debt, fixed interest rate	7.50%	7.50%				7.50%	7.50%
Restricted Stock Units
Significant Accounting Policies [Line Items]
Vesting period (in years)	4 years
June Amendment | Senior credit facility
Significant Accounting Policies [Line Items]
Line of credit facility, current borrowing capacity	$ 500,000
Subsequent Event | June Amendment | Senior credit facility
Significant Accounting Policies [Line Items]
Line of credit facility, current borrowing capacity					$ 340,000
Line of credit facility, target borrowing capacity				$ 500,000

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Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Disclosure of Cash Flow Information
Cash paid for interest, net of amounts capitalized	$ (296,386)	$ (235,793)	$ (274,850)
Cash (paid) received for income taxes	(88)	1,928	(4,610)
Supplemental Disclosure of Noncash Investing and Financing Activities
Deposit on pending sale	0	0	(255,000)
Change in accrued capital expenditures	177,586	(55,557)	72,848
Equity issued for debt	(63,299)	0	0
Preferred stock dividends paid in common stock	(16,188)	0	0
Long-term debt issued, including derivative and net of discount, for asset acquisition and termination of gathering agreement	$ (50,310)	$ 0	$ 0

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Acquisitions and Divestitures - Acquisitions (Details)	1 Months Ended		12 Months Ended
	Dec. 31, 2015 USD ($) a well	Oct. 31, 2015 USD ($) mi	Dec. 31, 2015 USD ($) a well	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Aug. 31, 2015
Property, Plant and Equipment [Line Items]
Payments to acquire oil and gas property and equipment			$ 216,943,000	$ 18,384,000	$ 17,028,000
Fair value of assets acquired			701,615,000	1,608,889,000	1,423,883,000
Loss on termination of the gathering contract			$ 50,976,000	$ 0	$ 0
Pinon Gathering Company LLC
Property, Plant and Equipment [Line Items]
Payments to acquire oil and gas property and equipment		$ 48,000,000
Principal amount of debt issued related to acquisition		$ 78,000,000.0
Number of miles of gathering lines acquired | mi		370
Fair value of consideration paid for acquisition		$ 98,300,000
Loss on termination of the gathering contract		51,000,000
Rockies Properties | North Park Basin, Jackson County, Colorado
Property, Plant and Equipment [Line Items]
Payments to acquire oil and gas property and equipment	$ 191,100,000
Number acres acquired | a	135,000		135,000
Proceeds from sale of oil and natural gas properties	$ 3,100,000
Number of wells acquired | well	16		16
Oil and Gas Properties | Pinon Gathering Company LLC
Property, Plant and Equipment [Line Items]
Fair value of assets acquired		$ 47,300,000
Senior Notes | 8.75% Senior Notes due 2020
Property, Plant and Equipment [Line Items]
Long-term debt, fixed interest rate	8.75%	8.75%	8.75%	8.75%		8.75%

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Acquisitions and Divestitures - Divestitures (Details) - Disposal Group, Disposed of by Sale, Not Discontinued Operations - USD ($)			12 Months Ended
	Feb. 25, 2014	Feb. 26, 2013	Dec. 31, 2013	Mar. 31, 2015	Dec. 31, 2014
Gulf Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and natural gas properties	$ 702,600,000
Guarantee period for certain plugging and abandonment obligations (up to)	1 year
Contingent liability equal to fair value of guarantees recorded as part of sale	$ 9,400,000				$ 5,100,000
Restricted deposits previously held in escrow, cash received				$ 12,000,000
Loss on sale of oil and gas property	0
Permian Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and natural gas properties		$ 2,600,000,000
Loss on sale of oil and gas property			$ 398,900,000
Permian Properties | Non-controlling Interest
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale of oil and gas property			$ 71,700,000
Asset Retirement Obligations | Gulf Properties
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Asset retirement obligations assumed	$ 366,000,000

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Acquisitions and Divestitures - Gulf Properties Disposal - Revenue and Expense Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 346,881	$ 394,107	$ 374,714	$ 443,056	$ 768,709	$ 1,558,758	$ 1,983,388
Expenses									$ 5,411,387	968,534	2,152,389
Gulf Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues										90,920	627,236
Expenses										$ 63,674	$ 491,991

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Acquisitions and Divestitures - Permian Properties Disposal - Revenue and Expense Information (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 346,881	$ 394,107	$ 374,714	$ 443,056	$ 768,709	$ 1,558,758	$ 1,983,388
Direct operating expenses									$ 375,354	$ 483,889	682,830
Permian Properties | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues											68,027
Direct operating expenses											$ 17,453

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Variable Interest Entities - Royalty Trusts - Common and Subordinated Units Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Mississippian Trust I
Variable Interest Entity [Line Items]
Total outstanding common units (in shares)	28,000,000	28,000,000
Total outstanding subordinated units (in shares)	0	0
Permian Trust
Variable Interest Entity [Line Items]
Total outstanding common units (in shares)	39,375,000	39,375,000
Total outstanding subordinated units (in shares)	13,125,000	13,125,000
Mississippian Trust II
Variable Interest Entity [Line Items]
Total outstanding common units (in shares)	37,293,750	37,293,750
Total outstanding subordinated units (in shares)	12,431,250	12,431,250

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Variable Interest Entities - Royalty Trusts - Ownership Interest (Details)	Dec. 31, 2015	Dec. 31, 2014
Mississippian Trust I
Variable Interest Entity [Line Items]
Beneficial interest owned by Company	26.90%	26.90%
Permian Trust
Variable Interest Entity [Line Items]
Beneficial interest owned by Company	25.00%	25.00%
Mississippian Trust II
Variable Interest Entity [Line Items]
Beneficial interest owned by Company	37.60%	37.60%

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Variable Interest Entities - Narrative (Details)	12 Months Ended
	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 31, 2015 mi	Mar. 31, 2014
Variable Interest Entity [Line Items]
Proceeds from the sale of royalty trust units	$ 0	$ 22,119,000	$ 28,985,000
Pinon Gathering Company LLC
Variable Interest Entity [Line Items]
Number of miles of gathering lines acquired | mi				370
Royalty Trusts
Variable Interest Entity [Line Items]
Percentage of royalty interest conveyed to company at trust termination	50.00%
Percentage of royalty interest sold at trust termination	50.00%
Percentage of subordinated units to total units	25.00%
Percentage of cash available in excess of target distribution paid for incentive distribution	50.00%
Conversion ratio of Royalty Trust subordinated unit to common units	1
Outstanding balance under loan commitment	$ 0	0
Noncontrolling interest in VIEs	510,200,000	1,300,000,000
Proceeds from the sale of royalty trust units		22,100,000	$ 29,000,000
Total liabilities	$ 1,060,000	$ 2,852,000
Grey Ranch Plant, L.P
Variable Interest Entity [Line Items]
Beneficial interest owned by Company			50.00%
Noncontrolling interest, ownership percentage by noncontrolling owners			50.00%
Noncontrolling interest, decrease from redemptions percentage					50.00%
Grey Ranch Plant Genpar, LLC (Genpar)
Variable Interest Entity [Line Items]
Beneficial interest owned by Company			50.00%
Noncontrolling interest, decrease from redemptions percentage					50.00%
Percentage ownership of another VIE			1.00%
Total liabilities			$ 0

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Variable Interest Entities - Royalty Trusts - Distributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Variable Interest Entity [Line Items]
Distributions to third-party unitholders	$ 138,305	$ 193,807	$ 206,470
Royalty Trusts
Variable Interest Entity [Line Items]
Total distributions	158,632	234,326	299,674
Distributions to third-party unitholders	$ 138,305	$ 193,807	$ 206,470

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Variable Interest Entities - Royalty Trusts - Assets and Liabilities Included in Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 435,588	$ 181,253	$ 814,663	$ 309,766
Accounts receivable	127,387	330,077
Derivative contracts	84,349	291,414
Total current assets	674,088	831,918
Investment in royalty interests	12,892,830	11,997,743	11,504,422
Less: accumulated depletion and impairment	(11,149,888)	(6,359,149)	(5,762,969)
Net oil and natural gas properties capitalized costs	1,742,942	5,638,594	$ 5,741,453
Accounts payable and accrued expenses	428,417	683,392
Royalty Trusts
Variable Interest Entity [Line Items]
Cash and cash equivalents	7,824	9,387
Accounts receivable	4,457	17,660
Derivative contracts	0	6,589
Total current assets	12,281	33,636
Investment in royalty interests	1,325,942	1,325,942
Less: accumulated depletion and impairment	(1,248,957)	(284,094)
Net oil and natural gas properties capitalized costs	76,985	1,041,848
Total assets	89,266	1,075,484
Accounts payable and accrued expenses	1,060	2,852
Total liabilities	$ 1,060	$ 2,852

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Variable Interest Entities - Royalty Trusts - Assets and Liabilities Included in Consolidated Balance Sheets (Additional Information) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Variable Interest Entity [Line Items]
Cumulative full cost ceiling limitation impairment charges	$ 8,200.0	$ 3,700.0
Royalty Trusts
Variable Interest Entity [Line Items]
Reserves for future expenses	3.0	3.0
Cumulative full cost ceiling limitation impairment charges	$ 976.2	$ 42.3

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Variable Interest Entities - PGC - Amounts due to/from the Company (Details) - Pinon Gathering Company LLC $ in Thousands	Dec. 31, 2014 USD ($)
Variable Interest Entity [Line Items]
Accounts receivable due from PGC	$ 1,141
Accounts payable due to PGC	$ 4,163

XML

Fair Value Measurements - Significant Unobservable Inputs - Derivative Contracts (Details) - Natural gas basis swaps - Fair Value Measurements Level 3 $ in Thousands	Dec. 31, 2015 USD ($) $ / Mcf	Dec. 31, 2014 USD ($) $ / Mcf
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair value | $	$ (1,748)	$ 350
Minimum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, forward price (usd/mcf)	(0.06)	(0.03)
Maximum
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, forward price (usd/mcf)	(0.28)	(0.38)
Weighted Average
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative, forward price (usd/mcf)	(0.22)	(0.29)

XML

Fair Value Measurements - Significant Unobservable Inputs - Long Term Debt Conversion Feature (Details) - Long-term debt holder conversion feature - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Fair Value	$ 29,355	$ 0
Fair Value Measurements Level 3
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Fair Value	$ 29,355
Minimum | Fair Value Measurements Level 3
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Hazard rate	114.00%
Maximum | Fair Value Measurements Level 3
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Hazard rate	135.20%
Weighted Average | Fair Value Measurements Level 3
Fair Value Inputs, Liabilities, Quantitative Information [Line Items]
Hazard rate	119.20%

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Fair Value Measurements - Assets and Liabilities Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring Basis
Commodity derivative contracts, assets, net of offset	$ 84,349	$ 338,417
Commodity derivative contracts, liabilities, net of offset	573	0
Fair Value, Measurements, Recurring
Fair Value Assets And Liabilities Measured On Recurring Basis
Netting adjustment, assets	(1,175)	0
Commodity derivative contracts, assets, net of offset	84,349	338,417
Investments	10,106	11,106
Assets measured at fair value	94,455	349,523
Guarantee		5,104
Netting adjustments, liabilities	(1,175)	0
Commodity derivative contracts, liabilities, net of offset	573
Liabilities measured at fair value	32,869	5,104
Fair Value, Measurements, Recurring | Long-term debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	29,355
Fair Value, Measurements, Recurring | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	2,941
Fair Value, Measurements, Recurring | Fair Value Measurements Level 1
Fair Value Assets And Liabilities Measured On Recurring Basis
Commodity derivative contracts, assets, before netting	0	0
Investments	10,106	11,106
Assets measured at fair value	10,106	11,106
Guarantee		0
Commodity derivative contracts, liabilities, before netting	0
Liabilities measured at fair value	0	0
Fair Value, Measurements, Recurring | Fair Value Measurements Level 1 | Long-term debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	0
Fair Value, Measurements, Recurring | Fair Value Measurements Level 1 | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	0
Fair Value, Measurements, Recurring | Fair Value Measurements Level 2
Fair Value Assets And Liabilities Measured On Recurring Basis
Commodity derivative contracts, assets, before netting	85,524	338,067
Investments	0	0
Assets measured at fair value	85,524	338,067
Guarantee		0
Commodity derivative contracts, liabilities, before netting	0
Liabilities measured at fair value	2,941	0
Fair Value, Measurements, Recurring | Fair Value Measurements Level 2 | Long-term debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	0
Fair Value, Measurements, Recurring | Fair Value Measurements Level 2 | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	2,941
Fair Value, Measurements, Recurring | Fair Value Measurements Level 3
Fair Value Assets And Liabilities Measured On Recurring Basis
Commodity derivative contracts, assets, before netting	0	350
Investments	0	0
Assets measured at fair value	0	350
Guarantee		5,104
Commodity derivative contracts, liabilities, before netting	1,748
Liabilities measured at fair value	31,103	$ 5,104
Fair Value, Measurements, Recurring | Fair Value Measurements Level 3 | Long-term debt holder conversion feature
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	29,355
Fair Value, Measurements, Recurring | Fair Value Measurements Level 3 | Mandatory prepayment feature - PGC Senior Secured Notes
Fair Value Assets And Liabilities Measured On Recurring Basis
Derivative liability, not subject to netting	$ 0

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Fair Value Measurements - Reconciliation of Fair Value Measurements for Commodity Derivative Contracts (Details) - Commodity derivatives contracts - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Level 3 Fair Value Measurements - Commodity Derivative Contracts
Beginning balance	$ 350	$ 0	$ (512)
Loss on commodity derivative contracts	(350)	0	(133)
Purchases	(1,748)	350	0
Settlements paid	0	0	645
Level 3 commodity derivative contracts at December 31	$ (1,748)	$ 350	$ 0

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Fair Value Measurements - Reconciliation of Fair Value Measurements for Long-Term Debt Holder Conversion Feature (Details) - Long-term debt holder conversion feature $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($)
Level 3 Fair Value Measurements - Long-Term Debt Holder Conversion Feature
Beginning balance	$ 0
Issuances	31,200
Gain on derivative holder conversion feature	10,198
Conversions	(12,043)
Ending balance	$ 29,355

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Fair Value Measurements - Reconciliation of Fair Value Measurements for Guarantee (Details) - Guarantee - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Level 3 Fair Value Measurements - Guarantee
Beginning balance	$ 5,104	$ 0
Issuances	0	9,446
Loss on guarantee	0	(4,342)
Settlements	(5,104)	0
Ending balance	$ 0	$ 5,104

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Fair Value Measurements - Estimated Fair Value and Carrying Value of Senior Notes (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	$ 3,631,506	$ 3,195,436
Secured Debt | 8.75% Senior Secured Notes Due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	1,301,098	0
Secured Debt | Fair Value Measurements Level 2 | 8.75% Senior Secured Notes Due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair Value	403,098	0
Senior Notes | 8.75% Senior Notes due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	392,666	445,402
Senior Notes | 7.5% Senior Notes due 2021
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	759,711	1,178,486
Senior Notes | 8.125% Senior Notes due 2022
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	527,737	750,000
Senior Notes | 7.5% Senior Notes due 2023
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	541,572	821,548
Senior Notes | Fair Value Measurements Level 2 | 8.75% Senior Notes due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair Value	39,740	303,750
Senior Notes | Fair Value Measurements Level 2 | 7.5% Senior Notes due 2021
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair Value	79,812	752,000
Senior Notes | Fair Value Measurements Level 2 | 8.125% Senior Notes due 2022
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair Value	57,749	472,500
Senior Notes | Fair Value Measurements Level 2 | 7.5% Senior Notes due 2023
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair Value	58,799	519,750
Convertible Debt | 8.125% Convertible Senior Notes due 2022
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	82,294	0
Convertible Debt | 7.5% Convertible Senior Notes due 2023
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Carrying Value	26,428	0
Convertible Debt | Fair Value Measurements Level 2 | 8.125% Convertible Senior Notes due 2022
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair Value	44,199	0
Convertible Debt | Fair Value Measurements Level 2 | 7.5% Convertible Senior Notes due 2023
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair Value	$ 15,125	$ 0

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Fair Value Measurements - Estimated Fair Value and Carrying Value of Senior Notes (Additional Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Oct. 31, 2015	Aug. 31, 2015	Jun. 30, 2015
8.125% Convertible Senior Notes due 2022
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	8.125%
7.5% Convertible Senior Notes due 2023
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	7.50%
Secured Debt | 8.75% Senior Secured Notes Due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	8.75%				8.75%
Debt maturity date	2020
Embedded derivative, fair value	$ 2,941		$ 2,800
Long term debt, discount	$ 29,842		$ 30,500
Senior Notes | 8.75% Senior Notes due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	8.75%	8.75%	8.75%	8.75%
Debt maturity date	2020	2020
Long term debt, discount	$ 3,269	$ 4,598
Senior Notes | 7.5% Senior Notes due 2021
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%	7.50%
Debt maturity date	2021	2021
Long term debt, premium	$ 1,944	$ 3,486
Senior Notes | 8.125% Senior Notes due 2022
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	8.125%	8.125%	8.125%	8.125%
Debt maturity date	2022	2022
Senior Notes | 7.5% Senior Notes due 2023
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%	7.50%
Debt maturity date	2023	2023
Long term debt, discount	$ 1,989	$ 3,452
Convertible Debt | 8.125% Convertible Senior Notes due 2022
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	8.125%	8.125%	8.125%	8.125%
Debt maturity date	2022	2022
Embedded derivative, fair value	$ 21,874
Long term debt, discount	$ 180,751
Convertible Debt | 7.5% Convertible Senior Notes due 2023
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%	7.50%
Debt maturity date	2023	2023
Embedded derivative, fair value	$ 7,481
Long term debt, discount	$ 59,549

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Fair Value Measurements - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2015	Oct. 31, 2015	Aug. 31, 2015	Jun. 30, 2015
Gulf Properties
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Fair value inputs, probability of default	3.71%
Secured Debt | 8.75% Senior Secured Notes Due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Debt instrument, face amount		$ 1,300,000,000	$ 78,000,000.0		$ 1,250,000,000.0
Long-term debt, fixed interest rate		8.75%			8.75%
Senior Notes | 8.75% Senior Notes due 2020
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Long-term debt, fixed interest rate	8.75%	8.75%	8.75%	8.75%
Mandatory prepayment feature, threshold amount of outstanding principal amount of senior notes		$ 100,000,000
Fair Value Measurements Level 3 | Gulf Properties
Fair Value Assets And Liabilities Measured On Recurring Basis [Line Items]
Estimate of future payments for plugging and abandonment	$ 372,000,000

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Accounts Receivable - Summary of Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Receivables [Abstract]
Oil, natural gas and NGL sales	$ 61,140	$ 139,848
Joint interest billing	60,403	170,937
Oil and natural gas services	2,417	21,436
Other	8,274	4,939
Accounts receivable, gross	132,234	337,160
Less: allowance for doubtful accounts	(4,847)	(7,083)	$ (11,061)	$ (5,635)
Total accounts receivable, net	$ 127,387	$ 330,077

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Accounts Receivable - Balance and Activity in Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Allowance for Doubtful Accounts
Beginning balance	$ 7,083	$ 11,061	$ 5,635
Additions charged to costs and expenses	1,320	818	5,497
Deductions	(3,556)	(4,796)	(71)
Ending balance	$ 4,847	$ 7,083	$ 11,061

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Accounts Receivable - Balance and Activity in Allowance for Doubtful Accounts (Additional Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Additions charged to costs and expenses	$ 1,320	$ 818	$ 5,497
Customer in Bankruptcy
Accounts, Notes, Loans and Financing Receivable [Line Items]
Additions charged to costs and expenses			$ 2,700

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Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and natural gas properties
Proved	$ 12,529,681	$ 11,707,147	$ 10,972,816
Unproved	363,149	290,596	531,606
Total oil and natural gas properties	12,892,830	11,997,743	11,504,422
Less: accumulated depreciation, depletion and impairment	(11,149,888)	(6,359,149)	(5,762,969)
Net oil and natural gas properties capitalized costs	1,742,942	5,638,594	$ 5,741,453
Land	14,260	16,300
Non-oil and natural gas equipment	373,687	602,392
Buildings and structures	227,673	263,191
Total	615,620	881,883
Less accumulated depreciation and amortization	(123,860)	(305,420)
Other property, plant and equipment, net	491,760	576,463
Total property, plant and equipment, net	$ 2,234,702	$ 6,215,057

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Property, Plant and Equipment (Additional Information) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Oil and gas proved properties
Property, Plant and Equipment [Line Items]
Cumulative capitalized interest	$ 48.9	$ 38.1
Non-oil and natural gas equipment
Property, Plant and Equipment [Line Items]
Cumulative capitalized interest	4.3	4.3
Building and structures
Property, Plant and Equipment [Line Items]
Cumulative capitalized interest	$ 20.4	$ 17.1

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Property, Plant and Equipment - Narrative (Details)	3 Months Ended	12 Months Ended
	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) $ / Boe	Dec. 31, 2014 USD ($) company $ / Boe	Dec. 31, 2013 USD ($) company $ / Boe	Jun. 30, 2015 USD ($)	May. 31, 2015 well	Jun. 30, 2014 USD ($) well
Property, Plant and Equipment [Line Items]
Cumulative full cost ceiling limitation impairment charges		$ 8,200,000,000	$ 3,700,000,000
Full cost ceiling impairments	$ 164,800,000	$ 4,500,000,000	$ 164,800,000	$ 0
Average depreciation and depletion rate (usd per Boe) | $ / Boe		10.67	15.00	16.81
Net value of assets held for sale		$ 491,760,000	$ 576,463,000
Loss on sale of assets		$ 1,491,000	$ 10,000	$ 399,086,000
Number of parties to agreements | company			2	2
Period during which target number of wells should be drilled for the carry commitment to be reduced				12 months
Expected completion of evaluation activities on majority of unproved properties		10 years
Repsol
Property, Plant and Equipment [Line Items]
Drilling carry received or billed			$ 205,600,000
Atinum and Repsol
Property, Plant and Equipment [Line Items]
Drilling carry received or billed				$ 408,000,000
Repsol
Property, Plant and Equipment [Line Items]
Minimum net wells | well							484
Net wells | well						453
Costs incurred toward satisfaction of obligation		$ 16,100,000
Repsol | Potential Drilling Carry Costs
Property, Plant and Equipment [Line Items]
Repsol's future drilling and completion costs, per well							$ 1,000,000
Future drilling and completion costs		31,000,000					$ 75,000,000.0
Drilling and Oil Field Services
Property, Plant and Equipment [Line Items]
Net value of assets held for sale		16,000,000			$ 20,000,000
Loss on sale of assets		$ 3,500,000

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Property, Plant and Equipment - Capitalized Costs of Unproved Properties Excluded from Amortization (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Abstract]
Property acquisition, cumulative	$ 362,803			$ 80,639
Property acquisition	197,849	$ 70,304	$ 14,011
Exploration, cumulative	34,988			339
Exploration	10,698	6,263	17,688
Total costs incurred, cumulative	397,791			$ 80,978
Total costs incurred	$ 208,547	$ 76,567	$ 31,699

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Property, Plant and Equipment - Capitalized Costs of Unproved Properties Excluded from Amortization (Additional Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Abstract]
Pipe inventory costs, cumulative	$ 34.7
Pipe inventory costs, period costs	$ 10.5	$ 6.2	$ 18.0

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Impairment - Narrative (Details)	3 Months Ended							12 Months Ended
	Dec. 31, 2015 USD ($) property	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Full cost ceiling impairments							$ 164,800,000	$ 4,500,000,000	$ 164,800,000	$ 0
Asset impairment charges	$ 886,800,000	$ 1,100,000,000	$ 1,500,000,000	$ 1,100,000,000				4,534,689,000	192,768,000	26,280,000
Net value of assets held for sale	$ 491,760,000				$ 576,463,000			491,760,000	576,463,000
Number of properties held for sale | property	1
Drilling and Oil Field Services
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Net value of assets held for sale	$ 16,000,000		$ 20,000,000					16,000,000
Drilling and Oilfield Services Assets - Permian Region
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges									24,300,000
Drilling Assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges					$ 24,300,000	$ 3,100,000		37,600,000	3,100,000	11,100,000
Gas Treating Plants and other Midstream Assets
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges								7,100,000	$ 600,000	12,200,000
Buildings
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges								$ 15,400,000
Corporate Asset
Schedule of Impaired Long-Lived Assets Held and Used and Intangible Assets [Line Items]
Asset impairment charges										$ 2,900,000

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Other Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Debt issuance costs, net of amortization	$ 72,259	$ 56,445
Deferred tax asset	0	95,843
Investments	10,106	11,106
Other	0	1,853
Total other assets	$ 82,365	$ 165,247

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Accounts Payable and Accrued Expenses (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Payables and Accruals [Abstract]
Accounts payable and other accrued expenses	$ 231,697	$ 392,500
Accrued interest	73,320	79,704
Production payable	55,260	120,573
Payroll and benefits	42,728	44,496
Convertible perpetual preferred stock dividends	21,572	11,072
Drilling advances	2,295	33,195
Related party	1,545	1,852
Total accounts payable and accrued expenses	$ 428,417	$ 683,392

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Construction Contract - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2013
Construction Contracts [Line Items]
Construction contract revenue	$ 0	$ 0	$ 23,349
Construction contract costs	$ 0	$ 0	23,349
Transmission Expansion Projects
Construction Contracts [Line Items]
Construction contract price				$ 23,300
Construction contract revenue			23,300
Construction contract costs			$ 23,300

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Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Senior credit facility	$ 0	$ 0
Total debt	3,631,506	3,195,436
Less: current maturities of long-term debt	0	0
Long-term debt	3,631,506	3,195,436
Secured Debt | 8.75% Senior Secured Notes due 2020, including mandatory prepayment feature liabilities of $2,941, and net of $29,842 discount
Debt Instrument [Line Items]
Total debt	1,301,098	0
Senior Notes | 8.75% Senior Notes due 2020, net of $3,269 and $4,598 discount, respectively
Debt Instrument [Line Items]
Total debt	392,666	445,402
Senior Notes | 7.5% Senior Notes due 2021, including a premium of $1,944 and $3,486, respectively
Debt Instrument [Line Items]
Total debt	759,711	1,178,486
Senior Notes | 8.125% Senior Notes due 2022
Debt Instrument [Line Items]
Total debt	527,737	750,000
Senior Notes | 7.5% Senior Notes due 2023, net of $1,989 and $3,452 discount, respectively
Debt Instrument [Line Items]
Total debt	541,572	821,548
Convertible Debt | 8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount
Debt Instrument [Line Items]
Total debt	82,294	0
Convertible Debt | 7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount
Debt Instrument [Line Items]
Total debt	$ 26,428	$ 0

XML

Long-Term Debt (Additional Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Oct. 31, 2015	Aug. 31, 2015	Jun. 30, 2015
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	8.125%
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount
Debt Instrument [Line Items]
Long-term debt, fixed interest rate	7.50%
Secured Debt | 8.75% Senior Secured Notes Due 2020
Debt Instrument [Line Items]
Debt maturity date	2020
Long-term debt, fixed interest rate	8.75%				8.75%
Long term debt, discount	$ 29,842		$ 30,500
Embedded derivative, fair value	$ 2,941		$ 2,800
Senior Notes | 8.75% Senior Notes due 2020, net of $3,269 and $4,598 discount, respectively
Debt Instrument [Line Items]
Debt maturity date	2020	2020
Long-term debt, fixed interest rate	8.75%	8.75%	8.75%	8.75%
Long term debt, discount	$ 3,269	$ 4,598
Senior Notes | 7.5% Senior Notes due 2021, including a premium of $1,944 and $3,486, respectively
Debt Instrument [Line Items]
Debt maturity date	2021	2021
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%	7.50%
Long term debt, premium	$ 1,944	$ 3,486
Senior Notes | 8.125% Senior Notes due 2022
Debt Instrument [Line Items]
Debt maturity date	2022	2022
Long-term debt, fixed interest rate	8.125%	8.125%	8.125%	8.125%
Senior Notes | 7.5% Senior Notes due 2023, net of $1,989 and $3,452 discount, respectively
Debt Instrument [Line Items]
Debt maturity date	2023	2023
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%	7.50%
Long term debt, discount	$ 1,989	$ 3,452
Convertible Debt | 8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount
Debt Instrument [Line Items]
Debt maturity date	2022	2022
Long-term debt, fixed interest rate	8.125%	8.125%	8.125%	8.125%
Long term debt, discount	$ 180,751
Embedded derivative, fair value	$ 21,874
Convertible Debt | 7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount
Debt Instrument [Line Items]
Debt maturity date	2023	2023
Long-term debt, fixed interest rate	7.50%	7.50%	7.50%	7.50%
Long term debt, discount	$ 59,549
Embedded derivative, fair value	$ 7,481

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Long-Term Debt - Narrative (Details) $ / shares in Units, shares in Millions		1 Months Ended				3 Months Ended	12 Months Ended
	Jun. 10, 2015 USD ($)	Oct. 31, 2015 USD ($)	Aug. 31, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2013 USD ($) $ / PrincipalAmount	Jun. 30, 2015 USD ($) shares	Dec. 31, 2015 USD ($) $ / shares shares	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 16, 2015 USD ($)	Aug. 13, 2015 USD ($)	Jun. 09, 2015 USD ($)
Debt Instrument [Line Items]
Write off of debt issuance costs							$ 7,108,000	$ 0	$ 0
Reduction in borrowing base for every $1 of junior lien debt incurred	$ 0.25
Senior credit facility outstanding amount							$ 0	0
Common stock issued for debt (in shares) | shares							92.8
Aggregate Principle of Notes Converted							$ 63,299,000	0	0
Gain (loss) on extinguishment of debt							641,131,000	$ 0	$ (82,005,000)
Aggregate cash payments for accrued interest and early conversion of debt							30,500,000
Long term debt maturing in 2020							1,700,000,000
Conversion of Senior Notes to Common Stock
Debt Instrument [Line Items]
Write off of debt issuance costs							5,200,000
Gain (loss) on extinguishment of debt						$ 17,900,000	$ 6,100,000
Repurchase of Senior Notes
Debt Instrument [Line Items]
Write off of debt issuance costs		$ 1,200,000	$ 3,200,000
Gain (loss) on extinguishment of debt		68,700,000	152,000,000		$ (82,000,000)
Conversion of Senior Notes to Convertible Debt
Debt Instrument [Line Items]
Write off of debt issuance costs		4,000,000	4,000,000
Gain (loss) on extinguishment of debt		$ 207,400,000	$ 189,000,000
8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate							8.125%
7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate							7.50%
Senior credit facility
Debt Instrument [Line Items]
Covenant, Ratio of secured debt to EBITDA, maximum												2.25
Covenant, Ratio of EBITDA to interest expense at Mar 2015												2.00
Covenant, Ratio of EBITDA to interest expense at Jun 2015												2.00
Covenant, Ratio of EBITDA to interest expense at Sep 2015												1.75
Covenant, Ratio of EBITDA to interest expense at Dec 2015												1.50
Covenant, Ratio of EBITDA to interest expense at Mar 2016												1.50
Covenant, Ratio of EBITDA to interest expense at Jun 2016												1.50
Covenant, Ratio of EBITDA to interest expense at Sep 2016												1.50
Covenant, Ratio of EBITDA to interest expense at Dec 2016												2.00
Current assets to current liabilities, ratio minimum												1.00
Covenant, Ratio of total net debt to EBITDA at Jun 2016												6.25
Covenant, Ratio of total net debt to EBITDA at Sep 2016												6.00
Covenant, Ratio of total net debt to EBITDA at Dec 2016												6.00
Covenant, Ratio of total net debt to EBITDA at Mar 2017												5.50
Covenant, Ratio of total net debt to EBITDA at Jun 2017												5.50
Covenant, Ratio of total net debt to EBITDA at Sep 2017												5.00
Covenant, Ratio of total net debt to EBITDA at Dec 2017												5.00
Covenant, Ratio of total net debt to EBITDA at Mar 2018												4.50
Line of credit facility, current borrowing capacity												$ 900,000,000
Line of credit facility, letters of credit outstanding							$ 11,000,000
Senior credit facility | August 2015 Amendment
Debt Instrument [Line Items]
Allowed repurchases of outstanding debt										$ 275,000,000	$ 200,000,000.0
Senior credit facility | June Amendment
Debt Instrument [Line Items]
Covenant, Ratio of secured debt to EBITDA, maximum							2.00
Current assets to current liabilities, ratio minimum							1.0
Line of credit facility, minimum collateral amount of proved oil and gas reserves representing the discounted present value of reserves used in borrowing base determination	80.00%
Line of credit facility maximum borrowings capacity	$ 1,000,000,000.0
Line of credit facility, current borrowing capacity							$ 500,000,000
Write off of debt issuance costs	4,900,000
Additional aggregate principal indebtedness permitted (less than)	$ 1,750,000,000.00
Senior credit facility | June Amendment | Maximum
Debt Instrument [Line Items]
Line of credit facility, unused capacity, commitment fee percentage	0.50%
Senior credit facility | June Amendment | London Interbank Offered Rate (LIBOR) | Minimum
Debt Instrument [Line Items]
Line of credit facility, basis spread on variable rate	1.75%
Senior credit facility | June Amendment | London Interbank Offered Rate (LIBOR) | Maximum
Debt Instrument [Line Items]
Line of credit facility, basis spread on variable rate	2.75%
Senior credit facility | June Amendment | Federal Funds
Debt Instrument [Line Items]
Line of credit facility, basis spread on variable rate	0.50%
Senior credit facility | June Amendment | One-Month Eurodollar Rate
Debt Instrument [Line Items]
Line of credit facility, basis spread on variable rate	1.00%
Senior credit facility | June Amendment | Base Rate | Minimum
Debt Instrument [Line Items]
Line of credit facility, basis spread on variable rate	0.75%
Senior credit facility | June Amendment | Base Rate | Maximum
Debt Instrument [Line Items]
Line of credit facility, basis spread on variable rate	1.75%
Junior Subordinated Debt | June Amendment
Debt Instrument [Line Items]
Outstanding junior debt threshold, reduction of maximum borrowing base	$ 1,500,000,000.00
Convertible Debt
Debt Instrument [Line Items]
Debt issuance costs							6,300,000
Debt conversion, original debt, amount							$ 255,300,000
Conversion ratio							0.3636
Convertible debt, threshold percentage of stock price trigger							40.00%
Initial conversion price threshold (usd per share) | $ / shares							$ 1.10
Convertible Debt | 8.125% Convertible Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		8.125%	8.125%				8.125%	8.125%
Embedded derivative, fair value							$ 21,874,000
Long term debt, discount							180,751,000
Aggregate Principle of Notes Converted		$ 269,400,000	$ 158,400,000
Debt conversion, original debt, amount							186,600,000
Debt conversion, original debt aggregate principal, net of discount and including holder's conversion feature							$ 54,400,000
Convertible Debt | 7.5% Convertible Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%				7.50%	7.50%
Embedded derivative, fair value							$ 7,481,000
Long term debt, discount							59,549,000
Aggregate Principle of Notes Converted			$ 116,600,000
Debt conversion, original debt, amount							68,700,000
Debt conversion, original debt aggregate principal, net of discount and including holder's conversion feature							19,300,000
Secured Debt | 8.75% Senior Secured Notes Due 2020
Debt Instrument [Line Items]
Debt instrument, face amount		$ 78,000,000.0		$ 1,250,000,000.0		$ 1,250,000,000.0	$ 1,300,000,000
Long-term debt, fixed interest rate				8.75%		8.75%	8.75%
Proceeds from debt, net of issuance costs				$ 1,210,000,000
Fair value of Notes awarded		50,300,000
Embedded derivative, fair value		2,800,000					$ 2,941,000
Long term debt, discount		30,500,000					29,842,000
Debt issuance costs							39,200,000
Senior Notes
Debt Instrument [Line Items]
Debt issuance costs							$ 48,900,000
Debt instrument, repurchased face amount		100,000,000	250,000,000
Repurchase of unsecured notes		30,000,000	94,500,000
Debt conversion, original debt, amount		$ 300,000,000	$ 275,000,000
Senior Notes | 8.75% Senior Notes due 2020
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		8.75%	8.75%				8.75%	8.75%
Long term debt, discount							$ 3,269,000	$ 4,598,000
Mandatory prepayment feature, threshold amount of outstanding principal amount of senior notes							$ 100,000,000
Debt instrument, repurchased face amount		$ 2,200,000	$ 29,300,000
Debt conversion, original debt, amount		$ 6,600,000	$ 15,900,000
Senior Notes | 7.5% Senior Notes due 2021
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%				7.50%	7.50%
Aggregate Principle of Notes Converted						$ 29,000,000
Debt instrument, repurchased face amount		$ 46,600,000	$ 111,600,000
Debt conversion, original debt, amount		$ 189,300,000	$ 40,700,000
Senior Notes | 8.125% Senior Notes due 2022
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		8.125%	8.125%				8.125%	8.125%
Aggregate Principle of Notes Converted						$ 21,000,000
Debt instrument, repurchased face amount			$ 26,100,000
Debt conversion, original debt, amount		$ 73,500,000	$ 101,800,000
Senior Notes | 7.5% Senior Notes due 2023
Debt Instrument [Line Items]
Long-term debt, fixed interest rate		7.50%	7.50%				7.50%	7.50%
Long term debt, discount							$ 1,989,000	$ 3,452,000
Debt instrument, repurchased face amount		$ 51,200,000	$ 83,000,000
Debt conversion, original debt, amount		$ 30,600,000	$ 116,600,000
Senior Notes | 7.5% Senior Notes Due 2021 And 8.125% Senior Notes Due 2022
Debt Instrument [Line Items]
Common stock issued for debt (in shares) | shares						28.0
Aggregate Principle of Notes Converted						$ 50,000,000
Debt conversion, original debt, amount							$ 50,000,000
Senior Notes | 9.875% Senior Notes Due 2016
Debt Instrument [Line Items]
Long-term debt, fixed interest rate					9.875%
Debt tender offer, aggregate principal amount					$ 365,500,000
Debt instrument redemption price per principal amount (usd per principal amount) | $ / PrincipalAmount					1,061.34
Senior Notes | 8.0% Senior Notes Due 2018
Debt Instrument [Line Items]
Long-term debt, fixed interest rate					8.00%
Debt tender offer, aggregate principal amount					$ 750,000,000
Debt instrument redemption price per principal amount (usd per principal amount) | $ / PrincipalAmount					1,052.77

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Derivatives - Offsetting Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
ASSETS
Derivative assets, gross amounts	$ 85,524	$ 338,417
Derivative assets, gross amounts offset	(1,175)	0
Derivative assets, amounts net of offset	84,349	338,417
Derivative assets, financial collateral	0	0
Derivative assets, net amount	84,349	338,417
LIABILITIES
Derivative liabilities, gross amounts	1,748	0
Derivative liabilities, gross amounts offset	(1,175)	0
Derivative liabilities, amount net of offset	573	0
Derivative liabilities, financial collateral	(573)	0
Derivative liabilities, net amount	0	0
Current assets
ASSETS
Derivative assets, gross amounts	85,524	291,414
Derivative assets, gross amounts offset	(1,175)	0
Derivative assets, amounts net of offset	84,349	291,414
Derivative assets, financial collateral	0	0
Derivative assets, net amount	84,349	291,414
Noncurrent assets
ASSETS
Derivative assets, gross amounts	0	47,003
Derivative assets, gross amounts offset	0	0
Derivative assets, amounts net of offset	0	47,003
Derivative assets, financial collateral	0	0
Derivative assets, net amount	0	47,003
Current liabilities
LIABILITIES
Derivative liabilities, gross amounts	1,748	0
Derivative liabilities, gross amounts offset	(1,175)	0
Derivative liabilities, amount net of offset	573	0
Derivative liabilities, financial collateral	(573)	0
Derivative liabilities, net amount	0	0
Noncurrent liabilities
LIABILITIES
Derivative liabilities, gross amounts	0	0
Derivative liabilities, gross amounts offset	0	0
Derivative liabilities, amount net of offset	0	0
Derivative liabilities, financial collateral	0	0
Derivative liabilities, net amount	$ 0	$ 0

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Derivatives - Open Commodity Derivative Contracts (Details) - January 2016 - December 2016 Mcf in Thousands	12 Months Ended
	Dec. 31, 2015 $ / Mcf $ / bbl MBbls Mcf
Oil price swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional (Oil in MBbl/Natural Gas in MMcf) | MBbls	1,464
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf)	88.36
Natural gas basis swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional (Oil in MBbl/Natural Gas in MMcf) | Mcf	10,980
Weighted Avg. Fixed Price (Oil in USD/bbl, Natural Gas in USD/mcf) | $ / Mcf	(0.38)
Oil collars—three way
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional (Oil in MBbl/Natural Gas in MMcf) | MBbls	2,556
Oil collars—three way | Purchased Put
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, floor (USD/bbl)	90.00
Put | Oil collars—three way | Sold
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, floor (USD/bbl)	83.14
Call | Oil collars—three way | Sold
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, cap (USD/bbl)	100.85

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Derivatives - Fair Value of Derivative Contracts (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets	$ 85,524	$ 338,417
Derivative liabilities	(1,748)	0
Total net derivative contracts	51,480	338,417
Current assets
Derivatives, Fair Value [Line Items]
Derivative assets	85,524	291,414
Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	47,003
Current liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(1,748)	0
Oil price swaps | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets	68,224	204,072
Oil price swaps | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	36,288
Natural gas price swaps | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	29,648
Natural gas basis swaps | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	350
Natural gas basis swaps | Current liabilities
Derivatives, Fair Value [Line Items]
Derivative liabilities	(1,748)	0
Oil collars—three way | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets	17,300	56,289
Oil collars—three way | Noncurrent assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	10,715
Natural gas collars | Current assets
Derivatives, Fair Value [Line Items]
Derivative assets	0	1,055
Long-term debt holder conversion feature | Long-term debt
Derivatives, Fair Value [Line Items]
Derivative liabilities	(29,355)	0
Mandatory prepayment feature - PGC Senior Secured Notes | Long-term debt
Derivatives, Fair Value [Line Items]
Derivative liabilities	$ (2,941)	$ 0

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Derivatives - Narrative (Details)	1 Months Ended			3 Months Ended								12 Months Ended
	Feb. 28, 2014 USD ($)	Apr. 30, 2013 USD ($)	Feb. 28, 2013 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) institution	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Oct. 31, 2015	Aug. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) loss on derivative contracts				$ (14,000,000)	$ (42,200,000)	$ 33,000,000	$ (49,800,000)	$ (329,200,000)	$ (132,600,000)	$ 85,300,000	$ 42,500,000	$ (73,061,000)	$ (334,011,000)	$ 47,123,000
Number of counterparties to open derivative contracts | institution												8
Interest expense												$ 321,421,000	244,109,000	270,234,000
Commodity Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) loss on derivative contracts												(73,100,000)	(334,000,000)	47,100,000
Commodity Derivatives | Cash
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) loss on derivative contracts												$ (327,700,000)	$ 32,300,000	(800,000)
Interest rate swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest expense														10,000
Interest rate swaps | Cash
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest expense														$ 2,400,000
Derivative Contracts Early Settlements | Commodity Derivatives | Cash
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) loss on derivative contracts	$ 69,600,000		$ 29,600,000
Senior Floating Rate Notes due 2014 | Fixed To Floating Interest Rate Swap Through April 1st 2013
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, maturity date		Apr. 01, 2013
Derivative liability, notional amount		$ 350,000,000.0
Derivative, fixed interest rate		6.69%
Senior Notes | 8.75% Senior Notes due 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Long-term debt, fixed interest rate				8.75%				8.75%				8.75%	8.75%		8.75%	8.75%
Mandatory prepayment feature, threshold amount of outstanding principal amount of senior notes				$ 100,000,000								$ 100,000,000
Lenders Of Senior Credit Facility [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of counterparties to open derivative contracts | institution												3

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Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis
Beginning balance	$ 54,402	$ 424,117	$ 498,410
Liability incurred upon acquiring and drilling wells	1,662	4,968	5,078
Revisions in estimated cash flows	44,060	(5,848)	(3,077)
Liability settled or disposed in current period	(1,023)	(377,927)	(113,071)
Accretion	4,477	9,092	36,777
Ending balance	103,578	54,402	424,117
Less: current portion	8,399	0	87,063
Asset retirement obligations, net of current	$ 95,179	$ 54,402	$ 337,054

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Asset Retirement Obligations - Reconciliation of Beginning and Ending Aggregate Carrying Amounts of Asset Retirement Obligations (Additional Information) (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Feb. 28, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]
Asset retirement obligation, liabilities settled		$ 1,023	$ 377,927	$ 113,071
Gulf of Mexico Properties
Reconciliation Of Changes In Asset Retirement Obligations [Line Items]
Asset retirement obligation, liabilities settled	$ 366,000

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Commitments and Contingencies - Future Minimum Lease Payments under Noncancelable Operating Leases (Details) $ in Thousands	Dec. 31, 2015 USD ($)
Years ending December 31
2016	$ 584
2017	555
2018	485
2019	72
2020	0
Thereafter	0
Total future obligation	$ 1,696

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Commitments and Contingencies - Oil and Natural Gas Transportation and Throughput Agreements (Details) - Transportation and Throughput Agreements $ in Thousands	Dec. 31, 2015 USD ($)
Years ending December 31
2016	$ 14,082
2017	13,869
2018	14,163
2019	9,282
2020	1,584
Thereafter	11,088
Total future obligation	$ 64,068

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Commitments and Contingencies - Narrative (Details) Mcf in Millions			12 Months Ended
	Oct. 07, 2015 USD ($)	Apr. 05, 2011 USD ($)	Dec. 31, 2015 USD ($) $ / Mcf Mcf	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Sep. 26, 2014 director	Jul. 15, 2013 plaintiff	Mar. 31, 2013 claim	Mar. 06, 2013 claim
Commitments and Contingencies Disclosure [Line Items]
Total rental expense under operating leases			$ 1,000,000	$ 1,700,000	$ 3,600,000
Number of independent company directors that formed a Special Litigation Committee | director						2
Number of claims consolidated by the court | claim									2
Treating Agreement
Commitments and Contingencies Disclosure [Line Items]
Contract agreement, term			30 years
Minimum delivery required (in Bcf) | Mcf			3,200.0
Initial shortfall price, per Mcf (in dollars per mcf) | $ / Mcf			0.25
Cumulative deliveries (in Bcf) | Mcf			73.1
Cumulative shortfall (in Bcf) | Mcf			439.6
Cumulative shortfall accrued			$ 109,900,000
Wesley West Minerals, Ltd and Longfellow Ranch Partners, LP
Commitments and Contingencies Disclosure [Line Items]
Loss contingency, damages sought, value		$ 45,500,000
General Land Office of the State of Texas
Commitments and Contingencies Disclosure [Line Items]
Loss contingency, damages sought, value		$ 13,000,000
Shareholder Derivative Actions
Commitments and Contingencies Disclosure [Line Items]
Number of putative shareholder derivative actions filed | claim								7
Rig Commitments
Commitments and Contingencies Disclosure [Line Items]
Minimum future commitments, 2016			2,500,000
Minimum future commitments, 2017			0
Federal Shareholder Derivative Litigation And Others | Pending Litigation
Commitments and Contingencies Disclosure [Line Items]
Proposed escrow fund amount to be established by insurers of individual defendants to litigation settlement	$ 38,000,000
James Hart And Other Named Plaintiffs
Commitments and Contingencies Disclosure [Line Items]
Number of additional plaintiffs | plaintiff							15
Reserve established for lawsuit			$ 5,100,000

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Equity - Preferred Stock (Details) - shares	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Shares authorized (in shares)	50,000,000	50,000,000	50,000,000
8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Shares outstanding at end of period (in shares)	2,650,000		2,650,000
7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Shares outstanding at end of period (in shares)	2,770,000		3,000,000

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Equity - Preferred Stock Additional Information (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock converted (in shares)	230,500
Common Stock
Class of Stock [Line Items]
Shares of common stock issued related to conversion of preferred stock (in shares)	2,968,000	18,423,000

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Equity - Preferred Stock Terms (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	8.50%	8.50%	8.50%
Liquidation preference per share (usd per share)	$ 100.00
Annual dividend per share (usd per share)	$ 8.50
Conversion rate per share to common stock (shares)	12.4805
7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage	7.00%	7.00%	7.00%
Liquidation preference per share (usd per share)	$ 100.00
Annual dividend per share (usd per share)	$ 7.00
Conversion rate per share to common stock (shares)	12.8791

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Equity - Preferred Stock Dividends (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Dividends satisfied in shares of common stock	$ 16,188	$ 0	$ 0
8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Dividends paid in cash	11,262	22,525	22,525
Dividends satisfied in shares of common stock	11,262	0	0
Accrued dividends at period end	8,447	8,447	8,447
7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Dividends paid in cash	0	21,000	21,000
Dividends satisfied in shares of common stock	10,500	0	0
Accrued dividends at period end	13,125	2,625	2,625
Dividends in arrears	10,500	0	0
6.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Dividends paid in cash	0	12,000	12,000
Accrued dividends at period end	$ 0	$ 0	$ 5,500

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Equity - Preferred Stock Dividends, Additional Information (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			12 Months Ended
	Aug. 17, 2015	May. 15, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
8.5% Convertible perpetual preferred stock
Class of Stock [Line Items]
Convertible perpetual preferred stock dividends (in shares)			18.6
Percentage multiplier used in calculation of value of shares issued			95.00%
Market value of common stock issued as dividends	$ 9.5
Common shares issued, value per preferred share (usd per share)	$ 3.58
Reduction to preferred stock dividends			$ 1.8
Preferred stock, dividend rate, percentage			8.50%	8.50%	8.50%
7.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Convertible perpetual preferred stock dividends (in shares)			5.7
Percentage multiplier used in calculation of value of shares issued			95.00%
Market value of common stock issued as dividends		$ 6.7
Common shares issued, value per preferred share (usd per share)		$ 2.23
Reduction to preferred stock dividends			$ 3.8
Preferred stock, dividend rate, percentage			7.00%	7.00%	7.00%
6.0% Convertible perpetual preferred stock
Class of Stock [Line Items]
Preferred stock, dividend rate, percentage				6.00%	6.00%

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Equity - Common Stock (Details) - shares	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Equity [Abstract]
Shares authorized (in shares)	1,800,000,000	1,800,000,000.0	800,000,000
Shares outstanding at end of period (in shares)	633,471,000		484,819,000
Shares held in treasury (in shares)	2,113,000		1,113,000

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Equity - Treasury Stock Activity (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity, Class of Treasury Stock [Line Items]
Value of shares withheld for taxes	$ 2,428	$ 6,373	$ 30,126
Value of shares retired	$ 0	$ 0	$ 0
Treasury Stock
Equity, Class of Treasury Stock [Line Items]
Number of shares withheld for taxes	1,872	1,034	5,679
Value of shares withheld for taxes	$ 2,428	$ 6,373	$ 30,126
Number of shares retired	1,872	1,034	5,679
Value of shares retired	$ 2,428	$ 6,373	$ 30,126

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Equity - Narrative (Details)	1 Months Ended			3 Months Ended	12 Months Ended
	Oct. 31, 2015 USD ($)	Aug. 31, 2015 USD ($)	Dec. 31, 2014 USD ($) $ / shares shares	Jun. 30, 2015 $ / shares shares	Dec. 31, 2015 USD ($) shares	Dec. 31, 2014 USD ($) $ / shares shares	Dec. 31, 2013	Nov. 29, 2012 right
Common Stock
Shares authorized (in shares)			800,000,000	1,800,000,000.0	1,800,000,000	800,000,000
Preferred stock, shares authorized (in shares)			50,000,000	50,000,000	50,000,000	50,000,000
Common stock issued for debt (in shares)					92,800,000
Shares repurchased then retired during period (in shares)						27,400,000
Shares repurchased then retired during period, value | $						$ 111,300,000
Broker fees and commission for shares repurchased, then retired | $						500,000
Additional paid-in capital—stockholder receivable | $			$ 2,500,000		$ 1,250,000	2,500,000
2014 Share Repurchase Program
Common Stock
Share repurchase program, maximum authorized amount | $			$ 200,000,000.0			$ 200,000,000.0
6.0% Convertible perpetual preferred stock
Preferred Stock
Preferred stock, dividend rate, percentage						6.00%	6.00%
Shares of common stock issued related to conversion of preferred stock (in shares)			18,400,000
Series A Junior Participating Preferred Stock | Stockholder Rights Plan
Common Stock
Number of Rights issued per common share | right								1
Common Stock and Preferred Stock
Common Stock
Shares authorized			850,000,000	1,850,000,000		850,000,000
Shares authorized, par value (usd per share) | $ / shares			$ 0.001	$ 0.001		$ 0.001
Common Stock
Preferred Stock
Shares of common stock issued related to conversion of preferred stock (in shares)					2,968,000	18,423,000
Common Stock
Common stock issued for debt (in shares)					120,881,000
Senior Notes
Common Stock
Debt conversion, original debt, amount | $	$ 300,000,000	$ 275,000,000
Senior Notes | Common Stock
Common Stock
Common stock issued for debt (in shares)					28,000,000
Convertible Debt
Common Stock
Debt conversion, original debt, amount | $					$ 255,300,000
Convertible Debt | Common Stock
Common Stock
Common stock issued for debt (in shares)					92,800,000
7.5% Senior Notes Due 2021 And 8.125% Senior Notes Due 2022 | Senior Notes
Common Stock
Common stock issued for debt (in shares)				28,000,000
Debt conversion, original debt, amount | $					$ 50,000,000

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Share-Based Compensation - Summary of Unvested Restricted Stock Awards (Details) - Restricted Stock - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of Shares
Unvested shares/units outstanding at beginning of period	8,556	7,643	15,328
Granted (in shares)	2,928	6,367	7,462
Vested (in shares)	(5,186)	(3,432)	(13,395)
Forfeited / Canceled (in shares)	(672)	(2,022)	(1,752)
Unvested shares/units outstanding at end of period	5,626	8,556	7,643
Weighted- Average Grant Date Fair Value (usd per share)
Unvested restricted shares outstanding at beginning of period (in usd per share)	$ 6.39	$ 6.92	$ 8.07
Granted (in usd per share)	0.88	6.17	6.32
Vested (in usd per share)	4.95	7.04	7.85
Forfeited / Canceled (in usd per share)	6.38	6.60	7.33
Unvested restricted shares outstanding at end of period (in usd per share)	$ 4.85	$ 6.39	$ 6.92

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Share-Based Compensation - Summary of Unvested Restricted Stock Units (Details) - Restricted Stock Units shares in Thousands	12 Months Ended
	Dec. 31, 2015 $ / shares shares
Vesting Four Years from Grant Date
Number of Shares
Unvested shares/units outstanding at beginning of period	0
Granted (in shares)	11,095
Vested (in shares)	(2,200)
Forfeited / Canceled (in shares)	(767)
Unvested shares/units outstanding at end of period	8,128
Fair value per unit (usd per share)
Fair Value per Unit at end of period (usd per share) | $ / shares	$ 0.20
Vesting Two Years from Grant Date
Number of Shares
Unvested shares/units outstanding at beginning of period	0
Granted (in shares)	3,104
Vested (in shares)	(979)
Forfeited / Canceled (in shares)	(122)
Unvested shares/units outstanding at end of period	2,003
Minimum | Vesting Two Years from Grant Date
Fair value per unit (usd per share)
Fair Value per Unit at end of period (usd per share) | $ / shares	$ 0.04
Maximum | Vesting Two Years from Grant Date
Fair value per unit (usd per share)
Fair Value per Unit at end of period (usd per share) | $ / shares	$ 0.20

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Share-Based Compensation - Performance Units/Performance Share Units - Fair Value Assumptions (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility factor	120.00%	55.60%
Weighted-average risk-free interest rate	0.70%	0.50%
Weighted-average fair value per unit (usd per unit)	$ 1.08	$ 13.85
Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Volatility factor	95.30%
Weighted-average risk-free interest rate	1.10%
Weighted-average fair value per unit (usd per unit)	$ 0.10

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Share-Based Compensation - Performance Units/Performance Share Units Activity (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Performance Units
Number of Shares
Outstanding at beginning of period (in shares)	66	31	0
Granted (in shares)	0	47	31
Vested (in shares)	(28)	0	0
Forfeited /canceled (in shares)	0	(12)	0
Outstanding at end of period (in shares)	38	66	31
Performance Units | Performance Period Ending December 2015
Number of Shares
Vested (in shares)	0	9	12
Unvested (in shares)	0	19	19
Performance Units | Performance Period Ending December 2016
Number of Shares
Vested (in shares)	26	13	0
Unvested (in shares)	12	25	0
Performance Share Units
Number of Shares
Outstanding at beginning of period (in shares)	0
Granted (in shares)	2,044
Forfeited /canceled (in shares)	(151)
Outstanding at end of period (in shares)	1,893	0
Performance Share Units | Performance Period Ending December 2017
Number of Shares
Vested (in shares)	695
Unvested (in shares)	1,198

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Share-Based Compensation - Narrative (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense		$ 21,700,000	$ 22,600,000	$ 90,200,000
Share-based compensation, capitalized		$ 5,900,000	$ 6,000,000	5,600,000
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		4 years
Unrecognized compensation cost related to unvested awards		$ 18,000,000
Unrecognized compensation cost, period of recognition (in years)		1 year 10 months 24 days
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		4 years
Performance Unit and Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)	3 years
Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost, period of recognition (in years)		1 year
Amount paid related to fully vested awards		$ 0
Performance Share Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards		$ 100,000
Unrecognized compensation cost, period of recognition (in years)		2 years
Vesting Four Years from Grant Date | Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		4 years
Unrecognized compensation cost related to unvested awards		$ 900,000
Unrecognized compensation cost, period of recognition (in years)		3 years 2 months 12 days
Vesting Two Years from Grant Date | Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period (in years)		2 years
Unrecognized compensation cost related to unvested awards		$ 200,000
Unrecognized compensation cost, period of recognition (in years)		1 year
Percentage vesting at the end of the first year		40.00%
Percentage vesting at the end of the second year		60.00%
Discount from common stock price using a credit spread, percentage		10.60%
Former Company Executives
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense				$ 48,500,000

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Incentive and Deferred Compensation Plans (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Final Payments Under Existing Cash Bonus Program
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Payments to employees	$ 10.9
Annual Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Accrued bonuses		$ 21.6	$ 21.1
Minimum | Management Annual Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Incentive plans, payout percentages of target values		0.00%
Maximum | Management Annual Incentive Plan
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Incentive plans, payout percentages of target values		200.00%
Deferred Compensation Plans
Defined Contribution Plan Disclosure [Line Items]
Retirement plan, employer matching contribution, percent of match		100.00%	100.00%	100.00%
Retirement plan, employer matching contribution, percent of employees' gross pay (up to)		10.00%	10.00%	15.00%
Retirement plan, cost recognized		$ 7.9	$ 8.7	$ 11.0
Deferred compensation plan, employer match percentage (up to)		10.00%	10.00%	15.00%
Deferred compensation plan, compensation expense		$ 2.9	$ 2.0	$ 2.7

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Income Taxes - (Benefit) Provision for Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
Federal	$ 0	$ (1,160)	$ 3,842
State	123	(1,133)	1,842
Current, total	123	(2,293)	5,684
Deferred
Federal	0	0	0
State	0	0	0
Deferred, total	0	0	0
Total provision (benefit)	123	(2,293)	5,684
Noncontrolling Interest
Deferred
Total provision (benefit)	90	283	308
Parent
Deferred
Total provision (benefit)	$ 33	$ (2,576)	$ 5,376

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Income Taxes - Reconciliation of Provision (Benefit) for Income Taxes at Statutory Federal Tax Rate to Company's Actual Income Tax Benefit (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation Of Provision Of Income Taxes [Line Items]
Total provision (benefit)	$ 123	$ (2,293)	$ 5,684
Parent
Reconciliation Of Provision Of Income Taxes [Line Items]
Computed at federal statutory rate	(1,512,325)	122,362	(178,078)
State taxes, net of federal benefit	(19,988)	4,145	(886)
Non-deductible expenses	816	1,895	2,589
Non-deductible debt costs	10,228	0	0
Stock-based compensation	6,700	1,467	7,611
Net effects of consolidating the non-controlling interests’ tax provisions	218,196	(34,614)	(13,901)
Change in valuation allowance	1,296,405	(96,769)	188,599
Other	1	(1,062)	(558)
Total provision (benefit)	$ 33	$ (2,576)	$ 5,376

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Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred tax liabilities
Investments	$ 138,310	$ 272,902
Property, plant and equipment	0	364,576
Derivative contracts	30,989	113,735
Long-term debt	10,017	0
Total deferred tax liabilities	179,316	751,213
Deferred tax assets
Property, plant and equipment	807,275	0
Allowance for doubtful accounts	18,702	19,086
Net operating loss carryforwards	1,190,799	1,265,458
Compensation and benefits	18,607	19,867
Alternative minimum tax credits and other carryforwards	44,302	43,840
Asset retirement obligations	38,314	21,946
CO2 under-delivery shortfall penalty	40,654	27,674
Other	4,305	2,934
Total deferred tax assets	2,162,958	1,400,805
Valuation allowance	(1,983,642)	(649,592)	$ (753,500)
Net deferred tax liability	$ 0	$ 0

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Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits
Unrecognized tax benefit at January 1	$ 77	$ 1,382
Changes to unrecognized tax benefits related to a prior year, increase	4
Changes to unrecognized tax benefits related to a prior year, decrease		(17)
Decreases to unrecognized tax benefits for settlements with tax authorities	0	(1,288)
Unrecognized tax benefit at December 31	$ 81	$ 77

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Income Taxes - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2010
Income Tax Disclosure [Abstract]
Valuation allowance	$ 1,983,642	$ 649,592	$ 753,500
Operating Loss Carryforwards [Line Items]
Unrecognized excess tax benefits from stock based compensation	17,700
Unrecognized tax benefits	$ 81	$ 77	$ 1,382
Earliest Tax Year
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards expiration year	2025
Latest Tax Year
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards expiration year	2035
Alternative Minimum Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Alternative minimum tax credits, not subject to expiration	$ 9,300
Domestic Tax Authority
Operating Loss Carryforwards [Line Items]
Federal net operating loss carryovers	3,200,000
Operating loss carryforwards subject to IRC Section 382 limitation				$ 929,400
Net operating loss carryovers, subject to expiration	$ 552,600

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Income Taxes - Periods Open to Tax Examination (Details)	12 Months Ended
	Dec. 31, 2015
Domestic Tax Authority | Earliest Tax Year
Income Tax Contingency [Line Items]
Open tax year	2012
Net Operating Loss And Other Carryforwards | Earliest Tax Year
Income Tax Contingency [Line Items]
Open tax year	2005
Net Operating Loss And Other Carryforwards | Latest Tax Year
Income Tax Contingency [Line Items]
Open tax year	2011
Minimum
Income Tax Contingency [Line Items]
Number of tax years open for state tax audit (in years)	3 years
Maximum
Income Tax Contingency [Line Items]
Number of tax years open for state tax audit (in years)	5 years

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(Loss) Earnings per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net (Loss) Income, Basic	$ (664,579)	$ (649,526)	$ (1,375,556)	$ (1,045,834)	$ 254,295	$ 145,957	$ (46,775)	$ (150,217)	$ (3,735,495)	$ 203,260	$ (609,414)
Weighted Average Shares, basic (in shares)									521,936	479,644	481,148
(Loss) Earnings Per Share, Basic earnings per share (in dollars per share)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 0.55	$ 0.30	$ (0.10)	$ (0.31)	$ (7.16)	$ 0.42	$ (1.27)
Effect of dilutive securities
Net (Loss) Income, Restricted stock (in dollars)									$ 0	$ 0	$ 0
Weighted Average Shares, Restricted stock (in shares)									0	2,181	0
Net (Loss) Income, Convertible preferred stock (in dollars)									$ 0	$ 6,500	$ 0
Weighted Average Shares, Convertible preferred stock (in shares)									0	17,918	0
Net (Loss) Income, Convertible senior unsecured notes (in dollars)									$ 0
Weighted Average Shares, Convertible senior unsecured note (in shares)									0
Net (Loss) Income, Diluted									$ (3,735,495)	$ 209,760	$ (609,414)
Weighted Average Shares, diluted (in shares)									521,936	499,743	481,148
(Loss) Earnings Per Share, Diluted earnings per share (in dollars per share)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 0.48	$ 0.27	$ (0.10)	$ (0.31)	$ (7.16)	$ 0.42	$ (1.27)

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(Loss) Earnings per Share - Calculation of Weighted Average Common Shares Outstanding used in Computation of Diluted Earnings Per Share (Additional Information) (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Convertible Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	71.2	71.7	90.1
Convertible Debt Securities
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	48.5
Restricted Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share			0.5
8.125% Convertible Senior Notes due 2022, including holder conversion feature liabilities of $21,874, and net of $180,751 discount
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Long-term debt, fixed interest rate	8.125%
7.5% Convertible Senior Notes due 2023, including holder conversion feature liabilities of $7,481, and net of $59,549 discount
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Long-term debt, fixed interest rate	7.50%
8.5% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage	8.50%	8.50%	8.50%
6.0% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage		6.00%	6.00%
7.0% Convertible perpetual preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Preferred stock, dividend rate, percentage	7.00%	7.00%	7.00%

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Related Party Transactions - Narrative (Details) - USD ($) $ in Thousands, shares in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Sales to related parties				$ 1,600
Employee termination benefits		$ 12,451	$ 8,874	122,505
Employee Severance
Related Party Transaction [Line Items]
Employee termination benefits		12,500		23,200
Former Chairman and CEO Severance
Related Party Transaction [Line Items]
Employee termination benefits	$ 57,900
Severance, compensation cost of accelerated shares	$ 36,800
Severance, number of accelerated shares	6.3
Severance liability		1,500
Annual Sponsorship Amount
Related Party Transaction [Line Items]
Sponsorship fees				$ 3,300
Annual Lease Obligation to Related Party
Related Party Transaction [Line Items]
Related party transaction amounts		500
Leasehold Improvements under Lease with Related Party
Related Party Transaction [Line Items]
Related party transaction amounts		$ 3,300
Gulf Properties | Employee Severance
Related Party Transaction [Line Items]
Employee termination benefits			$ 8,900

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Subsequent Events - Royalty Trust Distributions (Details) - Subsequent Event - USD ($) $ in Thousands	Feb. 26, 2016	Jan. 28, 2016
Royalty Trusts
Subsequent Event [Line Items]
Total Distribution		$ 23,093
Amount to be Distributed to Third-Party Unitholders	$ 19,609
Mississippian Trust I
Subsequent Event [Line Items]
Total Distribution		8,708
Amount to be Distributed to Third-Party Unitholders	6,367
Permian Trust
Subsequent Event [Line Items]
Total Distribution		7,560
Amount to be Distributed to Third-Party Unitholders	7,560
Mississippian Trust II
Subsequent Event [Line Items]
Total Distribution		$ 6,825
Amount to be Distributed to Third-Party Unitholders	$ 5,682

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Subsequent Events - Narrative (Details) $ in Thousands, shares in Millions				1 Months Ended				3 Months Ended	12 Months Ended
	Mar. 16, 2016 USD ($)	Mar. 15, 2016 USD ($)	Jan. 21, 2016 USD ($)	Feb. 29, 2016 USD ($)	Jan. 31, 2016 USD ($)	Oct. 31, 2015 USD ($)	Aug. 31, 2015 USD ($)	Mar. 20, 2016 USD ($) shares	Dec. 31, 2015 USD ($) MMBoe shares	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)	Mar. 21, 2016 USD ($)	Mar. 11, 2016 USD ($)	Feb. 16, 2016	Jun. 09, 2015 USD ($)
Subsequent Event [Line Items]
Employee termination benefits									$ 12,451	$ 8,874	$ 122,505
Senior credit facility, borrowed amount									$ 0	0
Debt instrument, subjective acceleration clause, period									30 days
Cash paid, transfer of ownership of substantially all of oil and natural gas properties and midstream assets in Pinon and release from all past, current and future claims and obligations under existing agreement									$ 24,889	$ 0	$ 0
Common stock issued for debt (in shares) | shares									92.8
Aggregate cash payments for accrued interest and early conversion of debt									$ 30,500
Treating Agreement
Subsequent Event [Line Items]
Contract agreement, term									30 years
Cumulative shortfall accrued									$ 109,900
Shortfall incurred in period									$ 34,900
Discontinued Operations, Disposed of by Means Other than Sale | WTO Properties
Subsequent Event [Line Items]
Production, oil and natural gas (in MMBoe) | MMBoe									1.9
Proved reserves, oil and natural gas (in MMBoe) | MMBoe									24.6
Revenue									$ 14,600
Operating expenses									41,100
Senior credit facility
Subsequent Event [Line Items]
Line of credit facility, current borrowing capacity															$ 900,000
Senior Notes
Subsequent Event [Line Items]
Debt conversion, original debt, amount						$ 300,000	$ 275,000
Convertible Debt
Subsequent Event [Line Items]
Debt conversion, original debt, amount									255,300
June Amendment | Senior credit facility
Subsequent Event [Line Items]
Line of credit facility, current borrowing capacity									$ 500,000
8.5% Convertible perpetual preferred stock
Subsequent Event [Line Items]
Preferred stock, dividend rate, percentage									8.50%	8.50%	8.50%
Subsequent Event
Subsequent Event [Line Items]
Employee termination benefits				$ 17,400
Senior credit facility, borrowed amount					$ 488,900
Common stock issued for debt (in shares) | shares								84.4
Aggregate cash payments for accrued interest and early conversion of debt								$ 33,500
Subsequent Event | Treating Agreement
Subsequent Event [Line Items]
Contract agreement, term			30 years
Subsequent Event | Discontinued Operations, Disposed of by Means Other than Sale | WTO Properties
Subsequent Event [Line Items]
Cash paid, transfer of ownership of substantially all of oil and natural gas properties and midstream assets in Pinon and release from all past, current and future claims and obligations under existing agreement			$ 11,000
Subsequent Event | Performance Incentive Plan | Minimum
Subsequent Event [Line Items]
Incentive plan, payout percentages of target values					0.00%
Subsequent Event | Performance Incentive Plan | Maximum
Subsequent Event [Line Items]
Incentive plan, payout percentages of target values					200.00%
Subsequent Event | Senior Notes
Subsequent Event [Line Items]
Interest payments		$ 22,000
Subsequent Event | June Amendment | Senior credit facility
Subsequent Event [Line Items]
Line of credit facility, current borrowing capacity													$ 340,000
Line of credit facility, target borrowing capacity												$ 500,000
Subsequent Event | 8.5% Convertible perpetual preferred stock
Subsequent Event [Line Items]
Preferred stock, dividend rate, percentage					8.50%
7.5% Senior Notes due 2023 | Senior Notes
Subsequent Event [Line Items]
Long-term debt, fixed interest rate						7.50%	7.50%		7.50%	7.50%
Debt conversion, original debt, amount						$ 30,600	$ 116,600
7.5% Senior Notes due 2023 | Subsequent Event | Senior Notes
Subsequent Event [Line Items]
Long-term debt, fixed interest rate														7.50%
7.5% Senior Notes due 2021 | Senior Notes
Subsequent Event [Line Items]
Long-term debt, fixed interest rate						7.50%	7.50%		7.50%	7.50%
Debt conversion, original debt, amount						$ 189,300	$ 40,700
7.5% Senior Notes due 2021 | Subsequent Event | Senior Notes
Subsequent Event [Line Items]
Interest payments	$ 28,400
8.125% Convertible Senior Notes due 2022
Subsequent Event [Line Items]
Long-term debt, fixed interest rate									8.125%
8.125% Convertible Senior Notes due 2022 | Convertible Debt
Subsequent Event [Line Items]
Long-term debt, fixed interest rate						8.125%	8.125%		8.125%	8.125%
Debt conversion, original debt, amount									$ 186,600
8.125% Convertible Senior Notes due 2022 | Subsequent Event | Convertible Debt
Subsequent Event [Line Items]
Debt conversion, original debt, amount								200,500
7.5% Convertible Senior Notes due 2023
Subsequent Event [Line Items]
Long-term debt, fixed interest rate									7.50%
7.5% Convertible Senior Notes due 2023 | Convertible Debt
Subsequent Event [Line Items]
Long-term debt, fixed interest rate						7.50%	7.50%		7.50%	7.50%
Debt conversion, original debt, amount									$ 68,700
7.5% Convertible Senior Notes due 2023 | Subsequent Event | Convertible Debt
Subsequent Event [Line Items]
Debt conversion, original debt, amount								$ 31,600

XML

Business Segment Information - Summarized Financial Information Concerning Segments (Details) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Sep. 30, 2014 USD ($)	Jun. 30, 2014 USD ($)	Mar. 31, 2014 USD ($)	Dec. 31, 2015 USD ($) business_unit segment	Dec. 31, 2014 USD ($) segment	Dec. 31, 2013 USD ($) segment
Segment Reporting [Abstract]
Reportable segments | segment									3	3	3
Business units | business_unit									3
Segment Reporting Information [Line Items]
Revenues	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 346,881	$ 394,107	$ 374,714	$ 443,056	$ 768,709	$ 1,558,758	$ 1,983,388
Income (loss) from operations	(959,406)	$ (1,059,733)	$ (1,535,083)	$ (1,088,456)	373,984	$ 256,491	$ 42,079	$ (82,330)	(4,642,678)	590,224	(169,001)
Interest income (expense), net									(321,421)	(244,109)	(270,234)
Gain (loss) on extinguishment of debt									641,131	0	(82,005)
Other income (expense), net									2,040	3,490	12,445
(Loss) income before income taxes									(4,320,928)	349,605	(508,795)
Capital expenditures									701,615	1,608,889	1,423,883
Depreciation, depletion, amortization and accretion									371,772	503,023	666,645
Total assets	2,991,155				7,259,225				2,991,155	7,259,225
Exploration and Production
Segment Reporting Information [Line Items]
Revenues									707,434	1,422,900	1,834,160
Income (loss) from operations									(4,461,907)	713,716	62,509
Interest income (expense), net									(42)	100	1,168
Gain (loss) on extinguishment of debt									0		0
Other income (expense), net									1,368	(423)	5,487
(Loss) income before income taxes									(4,460,581)	713,393	69,164
Capital expenditures									656,022	1,508,100	1,319,012
Depreciation, depletion, amortization and accretion									324,471	443,573	605,242
Total assets	1,959,975				6,273,802				1,959,975	6,273,802
Drilling and Oil Field Services
Segment Reporting Information [Line Items]
Revenues									22,124	76,088	66,641
Income (loss) from operations									(59,999)	(37,564)	(40,155)
Interest income (expense), net									0	0	0
Gain (loss) on extinguishment of debt									0		0
Other income (expense), net									13	(541)	0
(Loss) income before income taxes									(59,986)	(38,105)	(40,155)
Capital expenditures									4,632	18,385	7,125
Depreciation, depletion, amortization and accretion									17,438	29,105	33,291
Total assets	27,621				115,083				27,621	115,083
Midstream Services
Segment Reporting Information [Line Items]
Revenues									33,809	55,394	79,460
Income (loss) from operations									(15,218)	(9,094)	(21,567)
Interest income (expense), net									0	0	(209)
Gain (loss) on extinguishment of debt									0		0
Other income (expense), net									253	9	(3,222)
(Loss) income before income taxes									(14,965)	(9,085)	(24,998)
Capital expenditures									21,556	44,606	55,706
Depreciation, depletion, amortization and accretion									11,742	10,085	7,972
Total assets	254,212				219,691				254,212	219,691
All Other
Segment Reporting Information [Line Items]
Revenues									5,342	4,376	3,127
Income (loss) from operations									(105,554)	(76,834)	(169,788)
Interest income (expense), net									(321,379)	(244,209)	(271,193)
Gain (loss) on extinguishment of debt									641,131		(82,005)
Other income (expense), net									406	4,445	10,180
(Loss) income before income taxes									214,604	(316,598)	(512,806)
Capital expenditures									19,405	37,798	42,040
Depreciation, depletion, amortization and accretion									18,121	20,260	20,140
Total assets	$ 749,347				$ 650,649				749,347	650,649
Operating Segments
Segment Reporting Information [Line Items]
Revenues									861,229	1,763,380	2,205,052
Operating Segments | Exploration and Production
Segment Reporting Information [Line Items]
Revenues									707,446	1,423,073	1,834,480
Operating Segments | Drilling and Oil Field Services
Segment Reporting Information [Line Items]
Revenues									67,358	192,944	187,456
Operating Segments | Midstream Services
Segment Reporting Information [Line Items]
Revenues									81,083	142,987	179,989
Operating Segments | All Other
Segment Reporting Information [Line Items]
Revenues									5,342	4,376	3,127
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues									(92,520)	(204,622)	(221,664)
Intersegment Eliminations | Exploration and Production
Segment Reporting Information [Line Items]
Revenues									(12)	(173)	(320)
Intersegment Eliminations | Drilling and Oil Field Services
Segment Reporting Information [Line Items]
Revenues									(45,234)	(116,856)	(120,815)
Intersegment Eliminations | Midstream Services
Segment Reporting Information [Line Items]
Revenues									(47,274)	(87,593)	(100,529)
Intersegment Eliminations | All Other
Segment Reporting Information [Line Items]
Revenues									$ 0	$ 0	$ 0

XML

Business Segment Information - Summarized Financial Information Concerning Segments (Additional Information) (Details) - USD ($)	3 Months Ended					12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Full cost ceiling impairments					$ 164,800,000	$ 4,500,000,000	$ 164,800,000	$ 0
Asset impairment charges	$ 886,800,000	$ 1,100,000,000	$ 1,500,000,000	$ 1,100,000,000		4,534,689,000	192,768,000	26,280,000
Discontinued Operations, Disposed of by Sale | Permian Properties
Segment Reporting Information [Line Items]
Loss on sale of oil and gas property								398,900,000
Gas Treating Plants and other Midstream Assets
Segment Reporting Information [Line Items]
Asset impairment charges						7,100,000	600,000	12,200,000
Buildings
Segment Reporting Information [Line Items]
Asset impairment charges						15,400,000
Gas Gathering and Processing Equipment [Member]
Segment Reporting Information [Line Items]
Asset impairment charges						700,000
Corporate Asset
Segment Reporting Information [Line Items]
Asset impairment charges								2,900,000
CO2 Compression Facilities
Segment Reporting Information [Line Items]
Asset impairment charges								8,300,000
Exploration and Production
Segment Reporting Information [Line Items]
Full cost ceiling impairments						4,500,000,000	164,800,000
Drilling and Oil Field Services
Segment Reporting Information [Line Items]
Asset impairment charges						37,600,000	27,400,000	11,100,000
Midstream Services | Gas Treating Plants and other Midstream Assets
Segment Reporting Information [Line Items]
Asset impairment charges						$ 7,100,000	$ 600,000	$ 3,900,000

XML

Business Segment Information - Major Customers (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenue, Major Customer [Line Items]
Sales	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 346,881	$ 394,107	$ 374,714	$ 443,056	$ 768,709	$ 1,558,758	$ 1,983,388
Plains Marketing, L.P.
Revenue, Major Customer [Line Items]
Sales									$ 318,018	$ 597,117	$ 491,258
Percentage of revenue									41.40%	38.30%	24.80%
Shell Trading (US) Company
Revenue, Major Customer [Line Items]
Sales											$ 347,422
Percentage of revenue											17.50%
Targa Pipeline Mid-Continent West OK LLC [Member]
Revenue, Major Customer [Line Items]
Sales									$ 231,649	$ 333,027	$ 211,838
Percentage of revenue									30.10%	21.40%	10.70%

XML

Condensed Consolidating Financial Information - Condensed Consolidating Balance Sheets of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors' (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current assets
Cash and cash equivalents	$ 435,588	$ 181,253	$ 814,663	$ 309,766
Accounts receivable, net	127,387	330,077
Intercompany accounts receivable	0	0
Derivative contracts	84,349	291,414
Prepaid expenses	6,833	7,981
Other current assets	19,931	21,193
Total current assets	674,088	831,918
Property, plant and equipment, net	2,234,702	6,215,057
Investment in subsidiaries	0	0
Derivative contracts	0	47,003
Other assets	82,365	165,247
Total assets	2,991,155	7,259,225
Current liabilities
Accounts payable and accrued expenses	428,417	683,392
Intercompany accounts payable	0	0
Derivative contracts	573	0
Deferred tax liability	0	95,843
Other current liabilities	0	5,216
Asset retirement obligations	8,399	0	87,063
Total current liabilities	437,389	784,451
Investment in subsidiaries	0	0
Long-term debt	3,631,506	3,195,436
Asset retirement obligations	95,179	54,402	337,054
Other long-term obligations	14,814	15,116
Total liabilities	4,178,888	4,049,405
Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,697,917)	1,937,825
Noncontrolling interest	510,184	1,271,995
Total stockholders’ (deficit) equity	(1,187,733)	3,209,820	3,175,627	3,862,455
Total liabilities and stockholders’ (deficit) equity	2,991,155	7,259,225
Eliminations
Current assets
Cash and cash equivalents	0	0	0	0
Accounts receivable, net	0	(7)
Intercompany accounts receivable	(2,563,250)	(2,132,207)
Derivative contracts	0	(38,454)
Prepaid expenses	0	0
Other current assets	0	0
Total current assets	(2,563,250)	(2,170,668)
Property, plant and equipment, net	0	0
Investment in subsidiaries	(2,758,045)	(6,632,142)
Derivative contracts		0
Other assets	(5,902)	(5,902)
Total assets	(5,327,197)	(8,808,712)
Current liabilities
Accounts payable and accrued expenses	0	(7)
Intercompany accounts payable	(2,563,250)	(2,132,207)
Derivative contracts	0	(38,454)
Deferred tax liability		0
Other current liabilities		0
Asset retirement obligations	0
Total current liabilities	(2,563,250)	(2,170,668)
Investment in subsidiaries	(1,439,074)	(1,062,230)
Long-term debt	(5,902)	(5,902)
Asset retirement obligations	0	0
Other long-term obligations	0	0
Total liabilities	(4,008,226)	(3,238,800)
Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,829,155)	(6,841,907)
Noncontrolling interest	510,184	1,271,995
Total stockholders’ (deficit) equity	(1,318,971)	(5,569,912)
Total liabilities and stockholders’ (deficit) equity	(5,327,197)	(8,808,712)
Parent
Current assets
Cash and cash equivalents	426,917	170,468	805,505	300,228
Accounts receivable, net	0	7
Intercompany accounts receivable	1,226,994	751,376
Derivative contracts	0	0
Prepaid expenses	0	0
Other current assets	0	0
Total current assets	1,653,911	921,851
Property, plant and equipment, net	0	0
Investment in subsidiaries	2,749,514	6,606,198
Derivative contracts		0
Other assets	72,259	152,286
Total assets	4,475,684	7,680,335
Current liabilities
Accounts payable and accrued expenses	160,122	151,825
Intercompany accounts payable	1,337,688	1,365,210
Derivative contracts	0	0
Deferred tax liability		95,843
Other current liabilities		0
Asset retirement obligations	0
Total current liabilities	1,497,810	1,612,878
Investment in subsidiaries	1,038,303	928,217
Long-term debt	3,637,408	3,201,338
Asset retirement obligations	0	0
Other long-term obligations	80	77
Total liabilities	6,173,601	5,742,510
Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	(1,697,917)	1,937,825
Noncontrolling interest	0	0
Total stockholders’ (deficit) equity	(1,697,917)	1,937,825
Total liabilities and stockholders’ (deficit) equity	4,475,684	7,680,335
Guarantors
Current assets
Cash and cash equivalents	847	1,398	1,013	922
Accounts receivable, net	122,606	299,764
Intercompany accounts receivable	1,305,573	1,339,152
Derivative contracts	84,349	284,825
Prepaid expenses	6,826	7,971
Other current assets	19,931	21,193
Total current assets	1,540,132	1,954,303
Property, plant and equipment, net	2,124,532	5,137,702
Investment in subsidiaries	8,531	25,944
Derivative contracts		47,003
Other assets	16,008	18,197
Total assets	3,689,203	7,183,149
Current liabilities
Accounts payable and accrued expenses	265,767	526,941
Intercompany accounts payable	1,192,569	731,103
Derivative contracts	573	38,454
Deferred tax liability		0
Other current liabilities		5,216
Asset retirement obligations	8,399
Total current liabilities	1,467,308	1,301,714
Investment in subsidiaries	400,771	134,013
Long-term debt	0	0
Asset retirement obligations	95,179	54,402
Other long-term obligations	14,734	15,039
Total liabilities	1,977,992	1,505,168
Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	1,711,211	5,677,981
Noncontrolling interest	0	0
Total stockholders’ (deficit) equity	1,711,211	5,677,981
Total liabilities and stockholders’ (deficit) equity	3,689,203	7,183,149
Non-Guarantors
Current assets
Cash and cash equivalents	7,824	9,387	$ 8,145	$ 8,616
Accounts receivable, net	4,781	30,313
Intercompany accounts receivable	30,683	41,679
Derivative contracts	0	45,043
Prepaid expenses	7	10
Other current assets	0	0
Total current assets	43,295	126,432
Property, plant and equipment, net	110,170	1,077,355
Investment in subsidiaries	0	0
Derivative contracts		0
Other assets	0	666
Total assets	153,465	1,204,453
Current liabilities
Accounts payable and accrued expenses	2,528	4,633
Intercompany accounts payable	32,993	35,894
Derivative contracts	0	0
Deferred tax liability		0
Other current liabilities		0
Asset retirement obligations	0
Total current liabilities	35,521	40,527
Investment in subsidiaries	0	0
Long-term debt	0	0
Asset retirement obligations	0	0
Other long-term obligations	0	0
Total liabilities	35,521	40,527
Equity
SandRidge Energy, Inc. stockholders’ (deficit) equity	117,944	1,163,926
Noncontrolling interest	0	0
Total stockholders’ (deficit) equity	117,944	1,163,926
Total liabilities and stockholders’ (deficit) equity	$ 153,465	$ 1,204,453

XML

Condensed Consolidating Financial Information - Condensed Consolidating Statements of Operations of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors' (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Total revenues	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 346,881	$ 394,107	$ 374,714	$ 443,056	$ 768,709	$ 1,558,758	$ 1,983,388
Expenses
Direct operating expenses									375,354	483,889	682,830
General and administrative									150,166	122,865	330,425
Depreciation, depletion, amortization and accretion									371,772	503,023	666,645
Impairment	886,800	1,100,000	1,500,000	1,100,000					4,534,689	192,768	26,280
(Gain) loss on derivative contracts	(14,000)	(42,200)	33,000	(49,800)	(329,200)	(132,600)	85,300	42,500	(73,061)	(334,011)	47,123
Loss on settlement of contract									50,976	0	0
Loss (gain) on sale of assets									1,491	10	399,086
Total expenses									5,411,387	968,534	2,152,389
(Loss) income from operations	(959,406)	(1,059,733)	(1,535,083)	(1,088,456)	373,984	256,491	42,079	(82,330)	(4,642,678)	590,224	(169,001)
Equity earnings from subsidiaries									0	0	0
Interest (expense) income, net									(321,421)	(244,109)	(270,234)
Gain (loss) on extinguishment of debt									641,131	0	(82,005)
Other income (expense), net									2,040	3,490	12,445
(Loss) income before income taxes									(4,320,928)	349,605	(508,795)
Income tax expense (benefit)									123	(2,293)	5,684
Net (loss) income	$ (783,961)	$ (796,485)	$ (1,588,731)	$ (1,151,874)	$ 314,057	$ 197,499	$ (17,252)	$ (142,406)	(4,321,051)	351,898	(514,479)
Less: net (loss) income attributable to noncontrolling interest									(623,506)	98,613	39,410
Net (loss) income attributable to SandRidge Energy, Inc.									(3,697,545)	253,285	(553,889)
Eliminations
Condensed Financial Statements, Captions [Line Items]
Total revenues									(8)	(140)	(393)
Expenses
Direct operating expenses									(8)	(140)	(393)
General and administrative									0	0	0
Depreciation, depletion, amortization and accretion									0	0	0
Impairment									0	0	0
(Gain) loss on derivative contracts									0	0	0
Loss on settlement of contract									0
Loss (gain) on sale of assets									0		0
Total expenses									(8)	(140)	(393)
(Loss) income from operations									0	0	0
Equity earnings from subsidiaries									4,280,929	(534,121)	192,043
Interest (expense) income, net									0	0	0
Gain (loss) on extinguishment of debt									0		0
Other income (expense), net									0	0	0
(Loss) income before income taxes									4,280,929	(534,121)	192,043
Income tax expense (benefit)									0	0	0
Net (loss) income									4,280,929	(534,121)	192,043
Less: net (loss) income attributable to noncontrolling interest									(623,506)	98,613	39,410
Net (loss) income attributable to SandRidge Energy, Inc.									4,904,435	(632,734)	152,633
Parent
Condensed Financial Statements, Captions [Line Items]
Total revenues									0	0	0
Expenses
Direct operating expenses									0	0	0
General and administrative									213	331	329
Depreciation, depletion, amortization and accretion									0	0	0
Impairment									0	0	0
(Gain) loss on derivative contracts									0	0	0
Loss on settlement of contract									0
Loss (gain) on sale of assets									0		0
Total expenses									213	331	329
(Loss) income from operations									(213)	(331)	(329)
Equity earnings from subsidiaries									(4,017,082)	495,154	(195,118)
Interest (expense) income, net									(321,378)	(244,209)	(271,193)
Gain (loss) on extinguishment of debt									641,131		(82,005)
Other income (expense), net									0	0	0
(Loss) income before income taxes									(3,697,542)	250,614	(548,645)
Income tax expense (benefit)									3	(2,671)	5,244
Net (loss) income									(3,697,545)	253,285	(553,889)
Less: net (loss) income attributable to noncontrolling interest									0	0	0
Net (loss) income attributable to SandRidge Energy, Inc.									(3,697,545)	253,285	(553,889)
Guarantors
Condensed Financial Statements, Captions [Line Items]
Total revenues									682,778	1,341,531	1,675,481
Expenses
Direct operating expenses									364,483	467,175	654,080
General and administrative									145,796	118,249	323,808
Depreciation, depletion, amortization and accretion									339,647	446,149	581,435
Impairment									3,599,810	150,125	15,038
(Gain) loss on derivative contracts									(65,049)	(292,733)	24,702
Loss on settlement of contract									50,976
Loss (gain) on sale of assets									2,217		291,743
Total expenses									4,437,880	888,965	1,890,806
(Loss) income from operations									(3,755,102)	452,566	(215,325)
Equity earnings from subsidiaries									(263,847)	38,967	3,075
Interest (expense) income, net									(43)	100	959
Gain (loss) on extinguishment of debt									0		0
Other income (expense), net									1,910	3,521	16,173
(Loss) income before income taxes									(4,017,082)	495,154	(195,118)
Income tax expense (benefit)									0	0	0
Net (loss) income									(4,017,082)	495,154	(195,118)
Less: net (loss) income attributable to noncontrolling interest									0	0	0
Net (loss) income attributable to SandRidge Energy, Inc.									(4,017,082)	495,154	(195,118)
Non-Guarantors
Condensed Financial Statements, Captions [Line Items]
Total revenues									85,939	217,367	308,300
Expenses
Direct operating expenses									10,879	16,854	29,143
General and administrative									4,157	4,285	6,288
Depreciation, depletion, amortization and accretion									32,125	56,874	85,210
Impairment									934,879	42,643	11,242
(Gain) loss on derivative contracts									(8,012)	(41,278)	22,421
Loss on settlement of contract									0
Loss (gain) on sale of assets									(726)		107,343
Total expenses									973,302	79,378	261,647
(Loss) income from operations									(887,363)	137,989	46,653
Equity earnings from subsidiaries									0	0	0
Interest (expense) income, net									0	0	0
Gain (loss) on extinguishment of debt									0		0
Other income (expense), net									130	(31)	(3,728)
(Loss) income before income taxes									(887,233)	137,958	42,925
Income tax expense (benefit)									120	378	440
Net (loss) income									(887,353)	137,580	42,485
Less: net (loss) income attributable to noncontrolling interest									0	0	0
Net (loss) income attributable to SandRidge Energy, Inc.									$ (887,353)	$ 137,580	$ 42,485

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Condensed Consolidating Financial Information - Condensed Consolidating Statements of Cash Flows of SandRidge Energy, Inc. and Wholly Owned Subsidiary Guarantors and Non-Guarantors' (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	$ 373,537	$ 621,114	$ 868,630
Cash flows from investing activities
Capital expenditures for property, plant and equipment	(879,201)	(1,553,332)	(1,496,731)
Acquisition of assets	(216,943)	(18,384)	(17,028)
Proceeds from sale of assets	56,504	714,475	2,584,115
Other	56,504	(18,384)	(17,028)
Net cash (used in) provided by investing activities	(1,039,640)	(857,241)	1,070,356
Cash flows from financing activities
Proceeds from borrowings	2,065,000	0	0
Repayments of borrowings	(939,466)	0	(1,115,500)
Premium on debt redemption	0	0	(61,997)
Distributions to unitholders	(138,305)	(193,807)	(206,470)
Repurchase of common stock	0	(111,827)	0
Dividends paid—preferred	(11,262)	(55,525)	(55,525)
Intercompany borrowings (advances) , net	0	0	0
Other	(66,791)	(91,649)	5,403
Net cash provided by (used in) financing activities	920,438	(397,283)	(1,434,089)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	254,335	(633,410)	504,897
CASH AND CASH EQUIVALENTS, beginning of year	181,253	814,663	309,766
CASH AND CASH EQUIVALENTS, end of year	435,588	181,253	814,663
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	51,272	8,438	907
Cash flows from investing activities
Capital expenditures for property, plant and equipment	0	0	0
Acquisition of assets	0
Proceeds from sale of assets		0	0
Other	(18,543)	(47,780)	(109,831)
Net cash (used in) provided by investing activities	(18,543)	(47,780)	(109,831)
Cash flows from financing activities
Proceeds from borrowings	0
Repayments of borrowings	0		0
Premium on debt redemption			0
Distributions to unitholders	20,324	40,520	93,205
Repurchase of common stock		0
Dividends paid—preferred			0
Intercompany borrowings (advances) , net	0	0	0
Other	(53,053)	(1,178)	15,719
Net cash provided by (used in) financing activities	(32,729)	39,342	108,924
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	0	0	0
CASH AND CASH EQUIVALENTS, beginning of year	0	0	0
CASH AND CASH EQUIVALENTS, end of year	0	0	0
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	(326,674)	(240,932)	(239,026)
Cash flows from investing activities
Capital expenditures for property, plant and equipment	0	0	0
Acquisition of assets	0
Proceeds from sale of assets		0	0
Other	0	0	0
Net cash (used in) provided by investing activities	0	0	0
Cash flows from financing activities
Proceeds from borrowings	2,065,000
Repayments of borrowings	(939,466)		(1,115,500)
Premium on debt redemption			(61,997)
Distributions to unitholders	0	0	0
Repurchase of common stock		(111,827)
Dividends paid—preferred			(55,525)
Intercompany borrowings (advances) , net	(475,618)	(215,368)	2,009,146
Other	(66,793)	(66,910)	(31,821)
Net cash provided by (used in) financing activities	583,123	(394,105)	744,303
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	256,449	(635,037)	505,277
CASH AND CASH EQUIVALENTS, beginning of year	170,468	805,505	300,228
CASH AND CASH EQUIVALENTS, end of year	426,917	170,468	805,505
Guarantors
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	524,313	641,181	852,026
Cash flows from investing activities
Capital expenditures for property, plant and equipment	(879,201)	(1,553,332)	(1,496,731)
Acquisition of assets	(216,943)
Proceeds from sale of assets		711,728	2,566,742
Other	74,140	28,256	89,606
Net cash (used in) provided by investing activities	(1,022,004)	(813,348)	1,159,617
Cash flows from financing activities
Proceeds from borrowings	0
Repayments of borrowings	0		0
Premium on debt redemption			0
Distributions to unitholders	0	0	0
Repurchase of common stock		0
Dividends paid—preferred			0
Intercompany borrowings (advances) , net	497,140	215,373	(2,018,212)
Other	0	(42,821)	6,660
Net cash provided by (used in) financing activities	497,140	172,552	(2,011,552)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(551)	385	91
CASH AND CASH EQUIVALENTS, beginning of year	1,398	1,013	922
CASH AND CASH EQUIVALENTS, end of year	847	1,398	1,013
Non-Guarantors
Condensed Financial Statements, Captions [Line Items]
Net cash (used in) provided by operating activities	124,626	212,427	254,723
Cash flows from investing activities
Capital expenditures for property, plant and equipment	0	0	0
Acquisition of assets	0
Proceeds from sale of assets		2,747	17,373
Other	907	1,140	3,197
Net cash (used in) provided by investing activities	907	3,887	20,570
Cash flows from financing activities
Proceeds from borrowings	0
Repayments of borrowings	0		0
Premium on debt redemption			0
Distributions to unitholders	(158,629)	(234,327)	(299,675)
Repurchase of common stock		0
Dividends paid—preferred			0
Intercompany borrowings (advances) , net	(21,522)	(5)	9,066
Other	53,055	19,260	14,845
Net cash provided by (used in) financing activities	(127,096)	(215,072)	(275,764)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(1,563)	1,242	(471)
CASH AND CASH EQUIVALENTS, beginning of year	9,387	8,145	8,616
CASH AND CASH EQUIVALENTS, end of year	$ 7,824	$ 9,387	$ 8,145

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Condensed Consolidating Financial Information - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($)
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities, adjustments	$ (382.7)
Increase (decrease) in intercompany accounts payable	49.5
Increase (decrease) in accounts payable	(49.5)
Intercompany borrowings, adjustments	(382.7)
Guarantors
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities, adjustments	382.7
Increase (decrease) in intercompany accounts payable	(49.5)
Increase (decrease) in accounts payable	49.5
Property, plant and equipment net, adjustments	150.4
Intercompany borrowings, adjustments	382.7
Other investing activities, adjustments	193.8
Other financing Activities, Adjustments	(193.8)
Non-Guarantors
Condensed Financial Statements, Captions [Line Items]
Property, plant and equipment net, adjustments	(150.4)
Eliminations
Condensed Financial Statements, Captions [Line Items]
Other investing activities, adjustments	(193.8)
Other financing Activities, Adjustments	$ 193.8

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Supplemental Information on Oil and Natural Gas Producing Activities - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and natural gas properties
Proved	$ 12,529,681	$ 11,707,147	$ 10,972,816
Unproved	363,149	290,596	531,606
Total oil and natural gas properties	12,892,830	11,997,743	11,504,422
Less: accumulated depreciation, depletion and impairment	(11,149,888)	(6,359,149)	(5,762,969)
Net oil and natural gas properties capitalized costs	$ 1,742,942	$ 5,638,594	$ 5,741,453

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Supplemental Information on Oil and Natural Gas Producing Activities - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Acquisitions of properties
Proved	$ 35,376	$ 73,370	$ 21,130
Unproved	210,065	123,649	100,242
Exploration	29,297	41,070	82,775
Development	571,562	1,288,395	1,131,269
Total cost incurred	$ 846,300	$ 1,526,484	$ 1,335,416

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Supplemental Information on Oil and Natural Gas Producing Activities - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development (Additional Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration	$ 29,297	$ 41,070	$ 82,775
Seismic Costs
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Exploration	$ 7,100	$ 10,800	$ 6,700

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Supplemental Information on Oil and Natural Gas Producing Activities - Results of Operations from Oil and Natural Gas Producing Activities (Unaudited) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Revenues	$ 707,434	$ 1,420,879	$ 1,820,278
Expenses
Production costs	324,141	377,819	548,719
Depreciation and depletion	319,913	434,295	567,732
Accretion of asset retirement obligations	4,477	9,092	36,777
Impairment	4,473,787	164,779	0
Total expenses	5,122,318	985,985	1,153,228
(Loss) income before income taxes	(4,414,884)	434,894	667,050
Income tax expense (benefit)	126	(2,852)	(7,471)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$ (4,415,010)	$ 437,746	$ 674,521

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Supplemental Information on Oil and Natural Gas Producing Activities - Results of Operations from Oil and Natural Gas Producing Activities (Unaudited) (Additional Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Impairment	$ 4,473,787	$ 164,779	$ 0
Decrease in income tax benefit to include impact of the ceiling test impairment		$ 1,100

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Supplemental Information on Oil and Natural Gas Producing Activities - Summary of Changes in Estimated Oil and Natural Gas Reserves (Unaudited) (Details) Mcf in Thousands	12 Months Ended
	Dec. 31, 2015 MBbls Mcf	Dec. 31, 2014 MBbls Mcf	Dec. 31, 2013 MBbls Mcf	Dec. 31, 2012 MBbls Mcf
Oil Reserves
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance	126,031	142,641	262,045
Revisions of previous estimates	(70,708)	(18,687)	(13,969)
Acquisitions of new reserves	22,447	1,009	43
Extensions and discoveries	9,741	37,603	40,570
Sales of reserves in place		(25,659)	(131,769)
Production	(9,600)	(10,876)	(14,279)
Proved developed and undeveloped reserves, ending balance	77,911	126,031	142,641
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	48,639	79,022	83,893	136,605
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	29,272	47,009	58,748	125,440
Natural Gas Liquids
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance	91,786	59,052	67,994
Revisions of previous estimates	(37,384)	11,103	3,717
Acquisitions of new reserves	2,460	441	13
Extensions and discoveries	9,257	27,500	18,686
Sales of reserves in place		(2,516)	(29,067)
Production	(5,044)	(3,794)	(2,291)
Proved developed and undeveloped reserves, ending balance	61,075	91,786	59,052
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	51,089	56,823	35,807	33,785
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	9,986	34,963	23,245	34,209
Natural Gas
Proved Developed and Undeveloped Reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)
Proved developed and undeveloped reserves, beginning balance | Mcf	1,788,233	1,390,429	1,415,042
Revisions of previous estimates | Mcf	(759,106)	167,589	(53,432)
Acquisitions of new reserves | Mcf	15,952	12,527	363
Extensions and discoveries | Mcf	160,865	467,185	359,918
Sales of reserves in place | Mcf		(163,800)	(228,229)
Production | Mcf	(92,104)	(85,697)	(103,233)
Proved developed and undeveloped reserves, ending balance | Mcf	1,113,840	1,788,233	1,390,429
Proved developed reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf	964,617	1,203,447	951,609	896,701
Proved undeveloped reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf	149,223	584,786	438,820	518,341

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Supplemental Information on Oil and Natural Gas Producing Activities - Summary of Changes in Estimated Oil and Natural Gas Reserves - Noncontrolling Interests (Unaudited) (Additional Information) (Details) Mcf in Thousands	Dec. 31, 2015 MBbls Mcf	Dec. 31, 2014 MBbls Mcf	Dec. 31, 2013 MBbls Mcf	Dec. 31, 2012 MBbls Mcf
Oil Reserves
Reserve Quantities [Line Items]
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	77,911	126,031	142,641	262,045
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	61,075	91,786	59,052	67,994
Natural Gas Reserves
Reserve Quantities [Line Items]
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf	1,113,840	1,788,233	1,390,429	1,415,042
Non-controlling Interest | Oil Reserves
Reserve Quantities [Line Items]
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	7,004	11,027	13,569
Non-controlling Interest | Natural Gas Liquids
Reserve Quantities [Line Items]
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas)	3,694	4,761	4,737
Non-controlling Interest | Natural Gas Reserves
Reserve Quantities [Line Items]
Proved reserves (in MBbls for Oil and NGLs/MMcf for Natural Gas) | Mcf	50,508	70,833	69,693

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Supplemental Information on Oil and Natural Gas Producing Activities - Calculation of Weighted Average Per Unit Prices (Unaudited) (Details)	12 Months Ended
	Dec. 31, 2015 $ / Mcf $ / bbl	Dec. 31, 2014 $ / Mcf $ / bbl	Dec. 31, 2013 $ / Mcf $ / bbl
Oil Reserves
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas)	45.29	91.65	95.67
Natural Gas Liquids
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas)	12.68	32.79	31.40
Natural Gas
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Weighted Average Sales Price (USD per barrel for Oil and NGLs/USD per Mcf for Natural Gas) | $ / Mcf	1.87	3.61	3.65

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Supplemental Information on Oil and Natural Gas Producing Activities - Standardized Measure of Discounted Future Cash Flows (Unaudited) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Future cash inflows from production	$ 6,387,944	$ 21,022,320	$ 19,937,484
Future production costs	(2,731,542)	(6,499,366)	(6,843,713)
Future development costs	(838,945)	(1,810,201)	(2,546,680)
Future income tax expenses	(901)	(3,223,740)	(2,283,541)
Undiscounted future net cash flows	2,816,556	9,489,013	8,263,550
10% annual discount	(1,501,994)	(5,401,261)	(4,245,939)
Standardized measure of discounted future net cash flows	$ 1,314,562	$ 4,087,752	$ 4,017,611	$ 5,840,368

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Supplemental Information on Oil and Natural Gas Producing Activities - Standardized Measure of Discounted Future Net Cash Flows (Unaudited) (Additional Information) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 1,314,562	$ 4,087,752	$ 4,017,611	$ 5,840,368
Non-controlling Interest
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Standardized measure of discounted future net cash flows	$ 224,600	$ 643,300	$ 781,600

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Supplemental Information on Oil and Natural Gas Producing Activities - Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Present value, beginning balance	$ 4,087,752	$ 4,017,611	$ 5,840,368
Changes during the year
Revenues less production and other costs	(383,293)	(1,043,060)	(1,271,559)
Net changes in prices, production and other costs	(3,813,465)	331,694	271,566
Development costs incurred	217,596	364,262	474,275
Net changes in future development costs	273,437	(341,183)	(207,729)
Extensions and discoveries	230,055	1,785,963	1,406,102
Revisions of previous quantity estimates	(1,354,778)	(77,688)	(296,418)
Accretion of discount	512,483	477,458	711,385
Net change in income taxes	1,426,333	(256,371)	477,328
Purchases of reserves in-place	18,429	50,958	1,628
Sales of reserves in-place	0	(1,058,330)	(3,172,187)
Timing differences and other	100,013	(163,562)	(217,148)
Net change for the year	(2,773,190)	70,141	(1,822,757)
Present value, ending balance	$ 1,314,562	$ 4,087,752	$ 4,017,611

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Supplemental Information on Oil and Natural Gas Producing Activities - Estimate of Changes in Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves (Unaudited) (Additional Information) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Present value	$ 1,314,562	$ 4,087,752	$ 4,017,611	$ 5,840,368
Non-controlling Interest
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Present value	$ 224,600	$ 643,300	$ 781,600

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Supplemental Information on Oil and Natural Gas Producing Activities - Narrative (Details) Mcf in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015 USD ($) MMBoe MBbls Mcf	Dec. 31, 2014 USD ($) MMBoe MBbls Mcf	Dec. 31, 2013 USD ($) MMBoe MBbls Mcf	Dec. 31, 2012 USD ($)
Reserve Quantities [Line Items]
Percentage of proved reserves estimated by the Company	9.90%
Expected period without drilling activity		5 years
Acquisitions of new reserves (MMBoe) | MMBoe		3.5
Standardized measure of discounted future net cash flows | $	$ 1,314,562	$ 4,087,752	$ 4,017,611	$ 5,840,368
Oil Reserves
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)	9,741	37,603	40,570
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	70,708	18,687	13,969
Natural Gas Reserves
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf	160,865	467,185	359,918
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf	759,106	(167,589)	53,432
Natural Gas Liquids
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)	9,257	27,500	18,686
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	37,384	(11,103)	(3,717)
Gulf Properties
Reserve Quantities [Line Items]
Sale of reserves in place (MMBoe) | MMBoe		55.5
Permian Properties
Reserve Quantities [Line Items]
Proved reserves (in MMBoe) | MMBoe			198.9
Proved developed reserves as a percentage of total proved reserves			55.00%
Standardized measure of discounted future net cash flows | $			$ 2,500,000
Lower Commodity Price | Oil Reserves
Reserve Quantities [Line Items]
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	54,000
Lower Commodity Price | Natural Gas Reserves
Reserve Quantities [Line Items]
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf	687,000
Lower Commodity Price | Natural Gas Liquids
Reserve Quantities [Line Items]
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	36,000
North Park Basin, Jackson County, Colorado [Member]
Reserve Quantities [Line Items]
Acquisitions of new reserves (MMBoe) | MMBoe	27.6
Mid-Continent and Permian Basin | Oil Reserves
Reserve Quantities [Line Items]
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)		2,000
Mid-Continent
Reserve Quantities [Line Items]
Extensions and discoveries (in MMBoe) | MMBoe			119.2
Mid-Continent | Oil Reserves
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)	9,700
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	16,000	8,000
Mid-Continent | Natural Gas Reserves
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf	160,900
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas) | Mcf	74,000
Mid-Continent | Natural Gas Liquids
Reserve Quantities [Line Items]
Extensions and discoveries (in MBbls for Oil and NGLs/Mcf for Natural Gas)	9,300
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)	1,000
Permian Properties | Oil Reserves
Reserve Quantities [Line Items]
Revisions of previous estimates (in MBbls for Oil and NGLs/Mcf for Natural Gas)		9,000

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Quarterly Financial Results (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Total revenues	$ 143,642	$ 180,152	$ 229,607	$ 215,308	$ 346,881	$ 394,107	$ 374,714	$ 443,056	$ 768,709	$ 1,558,758	$ 1,983,388
(Loss) income from operations	(959,406)	(1,059,733)	(1,535,083)	(1,088,456)	373,984	256,491	42,079	(82,330)	(4,642,678)	590,224	(169,001)
Net (loss) income	(783,961)	(796,485)	(1,588,731)	(1,151,874)	314,057	197,499	(17,252)	(142,406)	(4,321,051)	351,898	(514,479)
(Loss applicable) income available to SandRidge Energy, Inc. common stockholders	$ (664,579)	$ (649,526)	$ (1,375,556)	$ (1,045,834)	$ 254,295	$ 145,957	$ (46,775)	$ (150,217)	$ (3,735,495)	$ 203,260	$ (609,414)
(Loss applicable) income available per share to SandRidge Energy, Inc. common stockholders
Basic (in dollars per share)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 0.55	$ 0.30	$ (0.10)	$ (0.31)	$ (7.16)	$ 0.42	$ (1.27)
Diluted (in dollars per share)	$ (1.13)	$ (1.23)	$ (2.78)	$ (2.19)	$ 0.48	$ 0.27	$ (0.10)	$ (0.31)	$ (7.16)	$ 0.42	$ (1.27)

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Quarterly Financial Results (Additional Information) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information [Line Items]
Full cost ceiling impairments								$ 164,800,000	$ 4,500,000,000	$ 164,800,000	$ 0
Asset impairment charges	$ 886,800,000	$ 1,100,000,000	$ 1,500,000,000	$ 1,100,000,000					4,534,689,000	192,768,000	26,280,000
(Gain) loss on derivative contracts	$ (14,000,000)	$ (42,200,000)	$ 33,000,000	$ (49,800,000)	$ (329,200,000)	$ (132,600,000)	$ 85,300,000	$ 42,500,000	(73,061,000)	(334,011,000)	47,123,000
Drilling Assets
Quarterly Financial Information [Line Items]
Asset impairment charges					$ 24,300,000		$ 3,100,000		37,600,000	3,100,000	11,100,000
Building and structures
Quarterly Financial Information [Line Items]
Asset impairment charges									15,400,000
Gas Treating Plants and other Midstream Assets
Quarterly Financial Information [Line Items]
Asset impairment charges									$ 7,100,000	$ 600,000	$ 12,200,000