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•	risks associated with drilling oil and natural gas wells;

•	the volatility of oil, natural gas and 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;

•	economic viability of certain natural gas production in west Texas due to high CO2 content;

•	risks associated with obligations to deliver minimum volumes of natural gas and/or CO2 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;

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•	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.

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•

Concentrate in Core Operating Area. The Company’s primary area of operation is the Mid-Continent area of Oklahoma and Kansas. By concentrating in this core area, the Company is able to (i) further build and utilize its technical expertise in order to interpret 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. Additionally, as operator of a majority of its wells, the Company has flexibility to utilize these competitive advantages to deliver strong, sustainable returns.

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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 was experienced during the second half of 2014 and is currently being experienced, the Company preserves capital and liquidity by contracting its capital expenditures budget and high-grading locations for development. During such times, the Company uses its decreased budgeted funds to capitalize 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 2015 capital expenditures budget is approximately $660 million, with approximately $610 million designated for exploration and production activities. This compares to 2014 total capital expenditures of approximately $1.6 billion and exploration and development capital expenditures of approximately $1.5 billion.

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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 area. 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 completion designs, well site production facilities, utilization of pad drilling 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.

•

Mitigate Commodity Price Risk. 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, as it has for 2015, 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.

•	Asset Monetization. The Company periodically evaluates its properties to identify opportunities to monetize assets and may use proceeds realized from such transactions to fund the drilling and development of its core area, for general corporate purposes or to retire corporate debt.

•	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.

•	Focus on Reservoirs with Known Hydrocarbon Production. The Company focuses its development efforts primarily in conventional, shallow, low-cost, permeable carbonate reservoirs with decades of production history. The nature of these reservoirs allows the Company to execute low-risk, repeatable drilling programs.

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Maintain Flexibility. The Company has multi-year inventories of both oil and natural gas drilling locations within its core operating area. Additionally, the Company maintains its own fleet of drilling rigs through its wholly owned drilling rig business. Maintaining inventories of both oil and natural gas drilling locations as well as its own drilling rigs 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, when appropriate, seeks to acquire them at a discount to other opportunities.

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(1)	For a reconciliation of PV-10 to Standardized Measure, see “—Proved Reserves.” The Company’s total Standardized Measure was $4.1 billion at December 31, 2014.

(2)	Average daily net production for the month of December 2014.

(3)	Estimated net proved reserves as of December 31, 2014 divided by production for the month of December 2014 annualized.

(4)	Capital expenditures for the year ended December 31, 2014 on an accrual basis.

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•	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 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 Executive Officer.

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•	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 internally generated reserves estimates to those prepared by third parties.

•	more than 27 years of practical experience in petroleum engineering and more than 25 years of experience estimating and evaluating reserve information;

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

•	a Bachelor of Science Degree in Petroleum Engineering.

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•	practicing consulting petroleum engineering since 2013 and over 14 years of prior industry experience;

•	licensed professional engineers in the state of Texas; and

•	Bachelor of Science Degree in Chemical Engineering

•	more than 58 years of practical experience in petroleum engineering and more than 54 years estimating and evaluating reserve information;

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

•	a Bachelor of Science Degree in Petroleum 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 and 2012, 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, 2014, 2013 and 2012. 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 an arbitrary 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, 2014, 2013 and 2012 include $33.9 million, $32.7 million and $8.5 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”;

•	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)	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 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.

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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;

•	natural disasters;

•	environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases or well fluids;

•	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.

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•	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.

•	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.

•	revenues, cash flow and profitability;

•	the Company’s ability to retain skilled rig personnel whom it would need in the event of an upturn in the demand for drilling and related services; and

•	the fair value of the Company’s rig fleet.

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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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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. For the three-month period ended December 31, 2014, 30,520 shares were reacquired at a weighted average price per share of $3.02 to satisfy tax obligations for vested employee stock awards.

(2)	Includes shares of common stock repurchased pursuant to a program approved by the Company’s Board of Directors and announced on September 4, 2014. Under the terms of the program, the Company may repurchase up to $200.0 million of the Company’s common stock. There is no fixed termination date for this repurchase program, which may be suspended or discontinued at any time.

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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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•	Drilled 442 wells, excluding salt water disposal wells, in the Mid-Continent area. Mid-Continent properties contributed approximately 23.4 MMBoe, or 80.9%, of the Company’s total production in 2014 compared to approximately 17.8 MMBoe, or 52.7%, in 2013.

•	Gulf Properties divested in February 2014, as discussed below, contributed production of approximately 1.3 MMBoe, or 4.6% of the Company’s total production in 2014 compared to approximately 10.1 MMBoe, or 29.8% of total production in 2013.

•	Total production for 2014 was comprised of approximately 37.6% oil, 49.3% natural gas and 13.1% NGLs compared to 42.3% oil, 50.9% natural gas and 6.8% NGLs in 2013.

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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)	Includes five rigs receiving stand-by rates from third parties at December 31, 2012.

(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 and 2012 were stacked. Non-operational rigs at December 31, 2013 were held for sale.

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(1)	Includes $150.4 million, $199.3 million and $181.2 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, 2014, 2013 and 2012, respectively.

(1)	Includes $51.0 million, $157.0 million and $75.4 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2014, 2013 and 2012, respectively. The expenses attributable to noncontrolling interest in consolidated VIEs include $29.9

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(1)	Includes interest on long-term debt.

(2)	Consists of a gas gathering agreement to deliver certain minimum volumes of natural gas to PGC, an unconsolidated variable interest entity. Pursuant to the agreement, the base fee for gathering services can be reduced if certain criteria are met. The amounts above are based on the base fee per the agreement.

(3)	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.

(4)	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 IRS annual limitations on qualified 401(k) retirement plans.

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temporarily suspends until June 30, 2016 the financial covenant requiring maintenance of certain levels for the ratio of total net debt to EBITDA, following which the ratio may not exceed 6.25:1.00 at June 30, 2016, 6.00:1.00 at September 30, 2016 and December 31, 2016, 5.50:1.00 at March 31, 2017 and June 30, 2017, 5.00:1.00 at September 30, 2017 and December 31, 2017 and 4.50:1.00 at March 31, 2018 and thereafter, calculated using annualized EBITDA for the fiscal quarter ended June 30, 2016 and the two subsequent fiscal quarters and otherwise calculated using the last four completed fiscal quarters;

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adopts additional financial covenants requiring the maintenance of agreed upon levels for the (a) ratio of total debt secured by assets of the Company and certain of its subsidiaries to EBITDA, which may not exceed 2.25:1.00 at each quarter end, calculated using the last four completed fiscal quarters, and (b) ratio of EBITDA to interest expense, which must be at least 2.00:1.00 at March 31, 2015 and June 30, 2015, 1.75:1.00 at September 30, 2015, 1.50:1.00 at each quarter end from December 31, 2015 to September 30, 2016, and 2.00:1.00 at December 31, 2016 and thereafter, calculated using the last four completed fiscal quarters;

•	increases the applicable margin used in the calculation of interest under the senior credit facility to (a) between 1.750% and 2.750% for interest determined by reference to LIBOR, and (b) between 0.750% and 1.750% for interest determined by reference to the base rate;

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permits the Company and certain of its subsidiaries to incur additional indebtedness in an aggregate principal amount not to exceed $500.0 million, which may be secured solely by collateral securing the senior credit facility on a junior lien basis, provided that such junior debt shall (a) if secured, be subject to the terms and conditions set forth in an intercreditor agreement, (b) mature no earlier than January 21, 2020 and (c) reduce the borrowing base under the senior credit facility by $0.25 for every $1.00 of junior debt incurred; and

•	limits the Company’s ability to make certain restricted payments by (a) reducing the amount of the basket exception to $200.0 million from $400.0 million and (b) requiring that the ratio of total net debt to EBITDA not exceed 4.5:1.0.

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(1)

Consideration paid by the Company consisted of 74 million shares of SandRidge common stock and cash of approximately $680.0 million. The value of the stock consideration is based upon the closing price of $7.33 per share of SandRidge common stock on April 17, 2012, which was the closing date of the Dynamic Acquisition. Under the acquisition method of accounting, the purchase price is determined based on the total cash paid and the fair value of SandRidge common stock issued on the acquisition date.

(2)	Cash consideration paid, including amounts paid to retire Dynamic’s long-term debt, was funded through a portion of the net proceeds from the Company’s issuance of $750.0 million of unsecured 8.125% Senior Notes due 2022.

(3)	In accordance with the acquisition agreement, the Company remitted to the seller a cash payment equal to Dynamic’s average daily cash balance for the 30-day period ending on the second day prior to closing. This resulted in an additional cash payment by the Company of $13.1 million at closing.

(4)	The estimated fair value of the acquired asset retirement obligations was determined using the Company’s credit adjusted risk-free rate.

(5)	The net deferred tax liability is primarily a result of the difference between the estimated fair value and the Company’s expected tax basis in the assets acquired and liabilities assumed. The net deferred tax liability also includes the effects of deferred tax assets associated with net operating losses and other tax attributes acquired as a result of the Dynamic Acquisition.

(6)

The fair value of oil and natural gas properties acquired was estimated using a discounted cash flow model, with future cash flows estimated based upon projections of oil and natural gas reserve quantities and weighted average oil and natural gas prices of $113.62 per barrel of oil and $3.83 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The commodity prices utilized were based upon commodity strip prices as of April 17, 2012 for the first four years and escalated for inflation at a rate of 2.0% annually beginning with the fifth year through the end of production. Future cash flows were discounted using an industry weighted average cost of capital rate.

(7)

The bargain purchase gain resulted from the excess of the fair value of net assets acquired over consideration paid. To validate the bargain purchase gain on this acquisition, the Company reviewed its initial identification and valuation of assets acquired and liabilities assumed. The Company believes it was able to acquire Dynamic for less than the estimated fair value of its net assets due to their offshore location resulting in less bidding competition.

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(1)

Pro forma net income, loss applicable to SandRidge Energy, Inc. common stockholders and loss per common share exclude a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release included in income tax benefit, $10.9 million of fees incurred to secure financing for the Dynamic Acquisition included in interest expense and $13.0 million of transaction costs incurred and included in general and administrative expense in the accompanying consolidated statement of operations for the year ended December 31, 2012.

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

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

(2)	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 this period.

(3)	The Company received incentive distributions from the Mississippian Trust I during the first and second quarters of 2012.

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(1)	Includes $3.0 million held by the trustee at December 31, 2014 and 2013 as reserves for future general and administrative expenses.

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

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(1)	Represents the fair value of the guarantees of certain plugging and abandonment obligations on behalf of Fieldwood as of February 25, 2014, the closing date for the sale of the Gulf Properties.

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(1)	Carrying value is net of $4,598 and $5,264 discount at December 31, 2014 and 2013, respectively.

(2)	Carrying value includes a premium, applicable to notes issued in August 2012, of $3,486 and $3,922 at December 31, 2014 and 2013, respectively.

(3)	Carrying value is net of $3,452 and $3,751 discount at December 31, 2014 and 2013, respectively.

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

(2)	Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established. Year ended December 31, 2014 represents write-off of allowance related to the sale of the Gulf Properties.

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(1)	Includes cumulative capitalized interest of approximately $38.1 million and $23.4 million at December 31, 2014 and 2013, respectively.

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

(3)	Includes cumulative capitalized interest of approximately $17.1 million and $12.0 million at December 31, 2014 and 2013, respectively.

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(1)	Includes $53.6 million of pipe inventory costs incurred ($21.3 million in 2014, $30.7 million in 2013 and $1.6 million in 2012 and prior years).

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(1)	Unamortized debt issuance costs associated with the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 were written off in March 2013 when the Company redeemed these notes. See Note 12 for discussion of the senior note redemptions.

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

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(1)	Liability settled or disposed in the current period includes $366.0 million associated with the Gulf Properties sold in February 2014, as discussed in Note 3.

(2)	Liability assumed in acquisition represents asset retirement obligations assumed in the acquisition of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.

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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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(1)	Conversion is dependent on certain factors, including the Company’s stock trading above specified prices for a set period.

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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)	Potential common shares related to the Company’s outstanding 8.5% and 7.0% convertible perpetual preferred stock covering 71.7 million shares for the year ended December 31, 2014 were excluded from the computation of earnings per share because their effect would have been antidilutive under the if-converted method.

(2)	Restricted stock awards covering 0.5 million shares were excluded from the computation of loss per share because their effect would have been antidilutive.

(3)	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 years ended December 31, 2013 and 2012, were excluded from the computation of earnings (loss) per share because their effect would have been antidilutive under the if-converted method.

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(1)

Income (loss) from operations includes a full cost ceiling impairment of $164.8 million for the year ended December 31, 2014, a loss on the sale of the Permian Properties of $398.9 million for the year ended December 31, 2013, an impairment of the Company’s goodwill of $235.4 million for the year ended December 31, 2012 and the Company’s (gain) loss on derivative contracts, including net cash payments upon settlement, for the years ended December 31, 2014, 2013 and 2012. See Note 13 for discussion of derivative contracts.

(2)	For the years ended December 31, 2014 and 2013, income (loss) from operations includes impairments of $27.4 million and $11.1 million, respectively, on certain drilling assets.

(3)	For the years ended December 31, 2014, 2013 and 2012, loss from operations includes impairments of the Company’s gas treating plants in west Texas and other midstream assets of $0.6 million, $3.9 million and $59.7 million, respectively.

(4)	For the year ended December 31, 2013, loss 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. For the year ended December 31, 2012, loss from operations includes a $19.6 million impairment of the Company’s CO2 compression facilities.

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

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(1)	Includes seismic costs of $10.8 million, $6.7 million and $15.3 million for 2014, 2013 and 2012, respectively.

(2)	Includes the Company’s share of Century Plant construction costs of $50.0 million for 2012. See Note 7.

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(1)	Reflects the Company’s effective tax rate, including the partial valuation allowance releases.

•	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, 2014, 2013 and 2012 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, 2014, 2013 and 2012 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 $643.3 million, $781.6 million and $952.7 million attributable to noncontrolling interests at December 31, 2014, 2013 and 2012 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 $643.3 million, $781.6 million and $952.7 million attributable to noncontrolling interests at December 31, 2014, 2013, and 2012 respectively.

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(1)	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.

(2)	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.

(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 $10.6 million impairment of various drilling assets and a $2.9 million impairment of a corporate asset in the second quarter of 2013 and a $2.1 million and $10.0 million impairment of certain midstream inventory, natural gas compressors, gas treating plants and a CO2 compression station in the second and fourth quarters of 2013, respectively.

(5)	Includes loss (gain) on derivative contracts of $40.9 million, $(103.7) million, $132.8 million and $(22.9) million for the first, second, third and fourth quarters, respectively.

(6)	Includes loss on sale of Permian Properties of $398.9 million in the first quarter of 2013.

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