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•	risks associated with drilling oil and natural gas wells;

•	the volatility of oil and natural gas prices;

•	uncertainties in estimating oil and natural gas reserves;

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

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

•	risks and liabilities associated with acquired properties and risks related to the integration of acquired businesses;

•	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, Gulf of Mexico and west Texas;

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

•	availability of natural gas production for the Company’s midstream services operations;

•	limitations of seismic data;

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

•	severe or unseasonable weather that may adversely affect production;

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

•	availability and terms of capital to fund capital expenditures;

•	amount and timing of proceeds of asset sales and asset monetizations;

•	substantial existing indebtedness;

•	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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•	risks associated with consent solicitations and proxy contests conducted by dissident stockholders;

•	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 need to maintain adequate internal control over financial reporting.

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•

Concentrate in Core Operating Areas. The Company’s primary areas of operation are (1) the Mid-Continent area of Oklahoma and Kansas and (2) the shallow water Gulf of Mexico. By concentrating in these core areas, the Company is able to (i) further build and utilize its technical expertise in order to interpret specific geological and operational trends, (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 and produced water disposal systems and (iv) opportunistically grow its holdings and operations in these areas to achieve production and reserve growth.

•

Focus on Conventional and Proven Reservoirs. The Company focuses its on-shore 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 with predictable production profiles and a higher certainty of economic returns. Further, due to these low pressure and shallow characteristics, the Company is able to maintain a low-cost operating structure and manage service costs.

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•	Invest in Infrastructure to Support Growth in Core Area. By constructing a saltwater disposal system and electrical infrastructure to service the Mississippian formation, 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.

•	Pursue Opportunistic Acquisitions. The Company periodically reviews acquisition targets to complement its existing asset base. Accordingly, 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.

•

Maintain Flexibility. The Company has multi-year inventories of both oil and natural gas drilling locations within its core operating areas. Additionally, the Company maintains its own fleet of drilling rigs through Lariat. 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.

•	Mitigate Commodity Price Risk. The Company enters into derivative contracts to mitigate 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.

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

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(1)	PV-10 generally differs from the Standardized Measure because it does not include the effects of income taxes on future net revenues. For a reconciliation of PV-10 to Standardized Measure, see “—Proved Reserves.” The Company’s total Standardized Measure was $5.8 billion at December 31, 2012.

(2)	Average daily net production for the month of December 2012.

(3)	Estimated net proved reserves as of December 31, 2012 divided by production for the month of December 31, 2012 annualized.

(4)	PV-10 includes costs associated with a 30-year CO2 treating agreement. Associated reserves are economically producible exclusive of these post-production costs. For further discussion of this treating agreement, see “Properties—Other” below.

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

•	the judgment of the personnel preparing the estimates.

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•	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 Reservoir Engineering Department reports directly to the Company’s President, independently from all of the Company’s operating divisions.

•	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.

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•	practical experience in petroleum engineering ranging from more than 14 years to more than 25 years and experience estimating and evaluating reserve information ranging from more than nine years to more than 20 years;

•	Licensed Professional Engineers in the states of Texas and Louisiana and Licensed Professional Geoscientists in the State of Texas; and

•	Bachelor of Science Degree in Civil Engineering, Bachelor of Science Degree in Mechanical Engineering and Master of Science Degree in Geology.

•	more than 57 years of practical experience in petroleum engineering and more than 53 years estimating and evaluating reserve information;

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

•	a Bachelor of Science Degree in Petroleum Engineering.

•	35 years of experience in oil and gas reservoir studies and reserve evaluations at the time of its most recent report;

•	a registered professional engineer in the state of Texas; 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 a 12-month average price for oil and natural gas. The prices used in the Company’s external and internal reserve reports yield weighted average wellhead prices, which are based on index prices and adjusted for transportation and regional price differentials. The index prices and the equivalent weighted average wellhead prices are shown in the table below.

(a)	At December 31, 2012, the weighted average wellhead oil price is higher than the index price as a result of favorable location differentials for production in the Gulf of Mexico. At December 31, 2011 and 2010, weighted average wellhead prices for oil included NGLs.

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(2)	Prior to 2012, NGLs did not comprise a significant portion of total proved reserves and were included with oil reserves, which affects the comparability of estimated reserves in 2012 to 2011 and 2010.

(3)	The Company’s production from the WTO contains natural gas that is high in CO2 content. These amounts are net of CO2 volumes that exceed pipeline quality specifications.

(4)

At December 31, 2012 and 2011, estimated total proved reserves attributable to noncontrolling interests were approximately 38.2 and 26.4 MMBoe, respectively, and Standardized Measure attributable to noncontrolling interests were approximately $952.7 million and $932.8 million, respectively. There were no proved reserves or Standardized Measure attributable to noncontrolling interests at December 31, 2010. See “Note 25—Supplemental Information on Oil and Natural Gas Producing Activities” in Item 8 of this report for additional information regarding reserve and Standardized Measure amounts attributable to noncontrolling interests.

(5)

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas 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, 2012, 2011 and 2010. 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 that 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:

(6)

Standardized Measure represents the present value of estimated future cash inflows from proved oil and natural gas 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)	Production is from the date property was acquired, or July 16, 2010, through December 31, 2010.

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(1)	Includes natural gas liquids.

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

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

(2)	For the year ended December 31, 2012, includes $8.5 million for amounts related to the Company’s shortfall in meeting its 2012 CO2 delivery obligations under a CO2 treating agreement as described under “—Properties—Other” 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 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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•	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;

•	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;

•	reductions in oil and natural gas prices;

•	oil and natural gas property title problems;

•	unique risks associated with offshore operations, such as potential oil spills and increased regulation; and

•	market limitations for oil and natural gas.

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

•	the price and quantity of foreign imports;

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

•	weather conditions and seasonal trends;

•	anticipated future prices of oil and natural gas, 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 acts of force majeure;

•	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 a substantial 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;

•	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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•	actual prices the Company receives for oil and natural gas;

•	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 and natural gas; 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 Company’s proved reserves;

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

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

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

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•	production is less than expected;

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

•	there is a change in the expected differential between the underlying price in the derivative contract and actual prices received.

•	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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•	difficulty in assimilating the operations and personnel of the acquired company;

•	difficulty in maintaining controls, procedures and policies during the transition and integration;

•	disruption of the Company’s ongoing business and distraction of its management and employees from other opportunities and challenges;

•	difficulty integrating the acquired company’s accounting, management information systems, human resources and other administrative systems;

•	inability to retain key personnel of the acquired business;

•	inability to achieve the financial and strategic goals for the acquired and combined businesses;

•	inability to take advantage of anticipated tax benefits;

•	potential failure of the due diligence processes to identify significant problems, liabilities or other shortcomings or challenges of an acquired business;

•	exposure to litigation and other potential liabilities in connection with environmental laws regulating exploration and production activities related to entities that the Company acquires, or that were previously acquired by such entities;

•	exposure to litigation or other claims in connection with, or inheritance of claims or litigation risk as a result of, an acquisition, including but not limited to, claims from terminated employees, customers, former stockholders or other third-parties;

•	potential inability to assert that internal control over financial reporting is effective; and

•	potential incompatibility of business cultures.

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•	The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases documentation requirements regarding the ability to respond to oil spills.

•	The Statement of Compliance NTL, which imposes requirements for operators regarding well design, construction and flow intervention processes and demonstration of adequate resources to respond to and contain spills, and also requires certifications of compliance from senior corporate officers.

•	The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain wellbore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.

•	The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (“SEMS”) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

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•	considering and responding to the consent solicitation and related actions by TPG-Axon, including, but not limited to, issues related to the qualifications of the Company’s Chief Executive Officer, Board and management, has been, and may continue to be, disruptive, costly and time-consuming, and a significant distraction for the Company’s management and employees;

•	perceived uncertainties as to the Company’s future direction, including, but not limited to, uncertainties related to the Company’s Chief Executive Officer, Board and management as well as the Company’s future status, may result in the loss of potential business opportunities and may make it more difficult to attract and retain qualified personnel;

•	if the TPG-Axon Nominees are elected to the Company’s Board of Directors and the Company’s Chief Executive Officer or other senior executives are removed, it may adversely affect the Company’s ability to create additional value for its stockholders by effectively implementing its business strategy;

•	the removal and replacement of a majority of the Board of Directors as a result of the TPG-Axon consent solicitation could constitute a “change of control” under certain of the Company’s material agreements, which could have material adverse consequences under such agreements;

•	the removal and replacement of a majority of the Board as a result of TPG-Axon’s consent solicitation would result in the accelerated vesting of a substantial number of shares of restricted stock held by employees and senior management, reducing the effectiveness of the restricted stock awards as tools for retaining individuals with expertise in the Company’s key operating areas; and

•

the actions taken by TPG-Axon have created an environment conducive to follow-on litigation, described below under Item 3, which serves as a further distraction to the Company’s management and employees and requires it to incur significant costs. Costs associated with the consent solicitation, related actions, and litigation may be substantial. Further, if determined adversely, such litigation could harm the Company’s business and have a material adverse effect on its results of operations.

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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 District Court of Oklahoma County, 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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•	Overview;

•	Results by Segment;

•	Consolidated Results of Operations;

•	Liquidity and Capital Resources;

•	Critical Accounting Policies and Estimates; and

•	New Accounting Pronouncements.

•	Acquired properties in the Gulf of Mexico during the second quarter of 2012 for a total of approximately $1.3 billion. These acquisitions significantly expanded the Company’s presence in the Gulf of Mexico and contributed production of approximately 7.0 MMBoe in 2012.

•	Drilled 396 wells in the Mid-Continent area during 2012. Mid-Continent properties contributed approximately 11.0 MMBoe, or 32.9%, of the Company’s total production in 2012 compared to approximately 4.9 MMBoe, or 20.9%, in 2011.

•	Increased oil production in 2012 by 6.1 MMBbls, or 51.8%, from 2011. Oil production comprised 53.5% of total production in 2012 compared to 50.6% of total production in 2011.

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(1)

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas 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 year ended December 31, 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 Permian Properties. The following table provides a reconciliation of the estimated Standardized Measure attributable to the Permian Properties to PV-10 attributable to the Permian Properties:

(a)	Standardized Measure was determined by allocating the Company’s Standardized Measure to the Permian Properties based on the PV-10 attributable to the Permian Properties relative to the Company’s total PV-10.

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(1)	Includes natural gas liquids.

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

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(1)	Represents revenues from the Company’s 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)	Includes a rig stacked at December 31, 2012 and 2011.

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(1)	Includes $181.2 million, $69.6 million and $5.6 million of revenues attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2012, 2011 and 2010, respectively.

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(1)	Includes $75.4 million, $15.1 million and $1.2 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2012, 2011 and 2010, respectively.

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(1)	Includes only the cash portion of the acquisitions.

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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, through June 30, 2029.

(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.

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•	while it is pending, it creates uncertainty that could result in the loss of potential business opportunities and may make it more difficult to attract and retain qualified personnel;

•	it has spurred follow-on litigation that can be costly to defend;

•	if successful, and the Company's Chief Executive Officer or other senior executives are removed, it may adversely affect the Company's ability to create additional value for its stockholders by effectively implementing its business strategy; and

•	if successful, it could result in a “change in control” that would constitute a default under the senior credit facility and require the Company to offer to repurchase its senior notes.

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(1)

The year ended December 31, 2012 includes $59.5 million of net realized gain related to early settlements of commodity derivative contracts and a $117.1 million non-cash realized loss on derivative contracts amended in January 2012. The years ended December 31, 2011 and 2010 include $48.1 million ($111.0 million realized gain and $62.9 million realized loss) and $114.5 million of realized gain, respectively, related to early settlements.

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(1)

Weighted average commodity prices utilized in the determination of the fair value of oil and natural gas properties were $105.58 per barrel of oil and $8.56 per Mcf of natural gas, after adjustment for transportation fees and regional price differentials. The prices utilized were based upon forward commodity strip prices, as of July 16, 2010, for the first four years and escalated for inflation at a rate of 2.5% annually beginning with the fifth year through the end of production, which was more than 50 years. These assumptions represent Level 3 inputs. Approximately 91.0% of the fair value allocated to oil and natural gas properties is attributed to oil reserves.

(2)

The Company received carryover tax basis in Arena’s assets and liabilities because the merger was not a taxable transaction under the Internal Revenue Code (“IRC”). Based upon the final purchase price allocation, a step-up in basis related to the property acquired from Arena resulted in a net deferred tax liability of approximately $454.5 million, which in turn contributed to an excess of the consideration transferred to acquire Arena over the estimated fair value on the acquisition date of the net assets acquired, or goodwill.

(1)	Includes a $454.5 million reduction in tax expense related to the release of a portion of the Company’s valuation allowance on existing deferred tax assets.

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•	On August 26, 2010, the Company sold certain deep acreage rights in the Cana Shale play in western Oklahoma for estimated net proceeds of $109.4 million, net of post-closing adjustments. The Company retained the shallow rights associated with this acreage.

•	On December 10, 2010, the Company sold approximately 40,000 net acres in the Avalon Shale and Bone Spring reservoirs of the Permian Basin for $102.1 million, net of post-closing adjustments. There was no production or proved reserves associated with these assets and the Company retained all rights above and below the Avalon Shale and Bone Spring formations.

•	In July 2011, the Company sold its Wolfberry assets in the Permian Basin for $151.6 million, net of fees and post-closing adjustments.

•	In August 2011, the Company sold certain oil and natural gas properties in Lea County and Eddy County, New Mexico, for $199.0 million, net of fees and post-closing adjustments.

•	In November 2011, the Company sold its east Texas natural gas properties in Gregg, Harrison, Rusk and Panola counties for $225.4 million, net of fees and post-closing adjustments.

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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 SandRidge of $13.1 million at closing.

(4)	The estimated fair value of the acquired asset retirement obligation 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 results from the excess of the fair value of net assets acquired over consideration paid and, as additional information becomes available, is subject to adjustment. To validate the estimated 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, income available to SandRidge Energy, Inc. common stockholders and earnings 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 statements of operations for the year ended December 31, 2012.

(2)	Pro forma net income, income applicable to SandRidge Energy, Inc. common stockholders and earnings per common share include a $122.7 million bargain purchase gain, a $100.3 million partial valuation allowance release, $10.9 million of fees incurred to secure financing for the Dynamic Acquisition and $13.0 million of estimated transaction costs.

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(1)	During the year ended December 31, 2012, the Company sold common units of the Mississippian Trust I and the Permian Trust it owned in transactions exempt from registration under Rule 144 under the Securities Act. These transactions decreased the Company’s beneficial interests in the Royalty Trusts. See further discussion of the unit sales below.

(2)	At the time each Royalty Trust terminates, 50% of the royalty interests conveyed to the Royalty Trust will automatically revert back to the Company, and the remaining 50% will be sold with the proceeds distributed to Royalty Trust unitholders.

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(1)	Includes $3.0 million and $2.0 million held by the trustee at December 31, 2012 and 2011, respectively, 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, and was determined by allocating the historical net book value of the Company’s full cost pool based on the fair value of each Royalty Trust’s royalty interests relative to the fair value of the Company’s full cost pool.

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(1)

Fair values related to the Company’s oil and natural gas fixed price swaps, natural gas collars and interest rate swap were transferred from Level 3 to Level 2 in the fourth quarter of 2011 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the years ended December 31, 2012 and 2010, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers between fair value hierarchy levels as of the end of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

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(3)	Carrying value includes a premium of $4,328 at December 31, 2012 applicable to notes issued in August 2012.

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(1)	Deductions represent write-off of receivables and collections of amounts for which an allowance had previously been established.

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(1)	Includes cumulative capitalized interest on oil and natural gas properties of $11.7 million and $1.6 million at December 31, 2012 and 2011, respectively.

(2)	Includes cumulative capitalized interest of approximately $11.4 million and $6.7 million at December 31, 2012 and 2011, respectively.

(1)	Includes $72.4 million of pipe inventory costs incurred ($54.9 million in 2012, $2.3 million in 2011, $5.1 million in 2010 and $10.1 million in 2009 and prior years).

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(1)

The year ended December 31, 2012 includes $59.5 million of net realized gain related to settlements of commodity derivative contracts with contractual maturities after the quarterly period in which they were settled (“early settlements”) and a $117.1 million non-cash realized loss on derivative contracts amended in January 2012. The years ended December 31, 2011 and 2010 include $48.1 million ($111.0 million realized gain and $62.9 million realized loss) and $114.5 million of realized gain, respectively, related to early settlements.

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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 District Court of Oklahoma County, Oklahoma

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(1)	Excludes approximately 0.7 million restricted shares from stock awards assumed in the Arena Acquisition. All of these awards had vested as of December 31, 2010.

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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)

Exploration and production segment income from operations includes unrealized (gains) losses of $(209.7) million, $(94.8) million and $275.2 million on commodity derivative contracts for the years ended December 31, 2012, 2011 and 2010, respectively, and impairment of the Company’s goodwill of $235.4 million for the year ended December 31, 2012. For the year ended December 31, 2012, the loss from operations for the midstream services segment includes a $59.7 million impairment of the Company’s gas treating plants in west Texas and the loss from operations in the All Other column includes a $19.6 million impairment of the Company’s CO2 compression facilities.

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

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(1)	Includes seismic costs of $15.3 million, $4.9 million and $4.1 million for 2012, 2011 and 2010, respectively.

(2)	Includes loss on the construction of the Century Plant of $50.0 million, $25.0 million and $105.0 million for 2012, 2011 and 2010, respectively. See Note 12.

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

•	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 and natural gas; 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)	Prior to 2012, NGLs did not comprise a significant portion of total proved reserves and were included with oil reserves, which affects the comparability of estimated reserves for 2012, 2011 and 2010.

(3)	Proved reserves at December 31, 2012 and 2011, respectively, include approximately 17,340 MBbls and 17,018 MBbls of oil, 5,132 MBbls and 1,782 MBbls of NGLs and 94,543 MMcf and 45,500 MMcf of natural gas attributable to noncontrolling interests.

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•	the standardized measure includes the Company’s estimate of proved oil, natural gas and natural gas liquids reserves and projected future production volumes based upon economic conditions;

•	pricing is applied based upon 12-month average market prices at December 31, 2012, 2011 and 2010 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 $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2012 and 2011, 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 $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2012 and 2011, respectively.

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(1)	Includes a $235.4 million goodwill impairment and a $79.3 million impairment of gas treating plants and CO2 compression facilities in the fourth quarter of 2012.

(2)	Includes unrealized losses (gains) of $129.2 million, $(580.7) million, $222.5 million and $19.3 million on commodity derivative contracts for the first, second, third and fourth quarters, respectively.

(3)	Includes adjustments of $(4.8) million retrospectively applied to the second quarter of 2012 as a result of measurement period adjustments made to the preliminary purchase price allocation for the Dynamic Acquisition in the fourth quarter of 2012.

(4)

(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.

(5)	Includes unrealized losses (gains) of $269.0 million, $(188.3) million, $(604.6) million and $429.1 million on commodity derivative contracts for the first, second, third and fourth quarters, respectively.

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