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•	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;

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•	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.

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(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.

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•	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.

•	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.

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•	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.

•	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;

•	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

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(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.

(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:

(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:

(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.

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

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(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.

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

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•	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.

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(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.

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•	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.

•	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.

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•	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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•	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.

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•	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.

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•	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.

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•	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.

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

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

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

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

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

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

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

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

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(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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(1)	Includes employee termination benefits.

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•	Overview;

•	Results by Segment;

•	Consolidated Results of Operations;

•	Liquidity and Capital Resources;

•	Valuation Allowance; and

•	Critical Accounting Policies and Estimates.

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•	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.

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(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.

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(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.

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(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.

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(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.

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(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.

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

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

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(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.

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(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.

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(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.

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(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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(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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(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.

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

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

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

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

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

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

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

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(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.

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(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.

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(1)	Restricted stock units which vested during the year ended December 31, 2015 were settled by the issuance of common stock.

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(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.

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(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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(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.

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

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

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

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(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.

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(1)	Includes seismic costs of $7.1 million, $10.8 million and $6.7 million for 2015, 2014 and 2013, respectively.

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(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.

•	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.

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(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:

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•	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:

•	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.

(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.

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(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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(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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