---

---

A.	Part I, Item 1. Business

B.	Part II, Item 6. Selected Financial Data

C.	Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

D.	Part II, Item 8. Financial Statements and Supplementary Data

E.	Part II, Item 9A. Controls and Procedures

F.	Part IV, Item 15. Exhibits and Financial Statement Schedules

---

---

•	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;

•	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;

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

•	potential financial losses or earnings reductions from commodity derivatives;

•	potential elimination or limitation of tax incentives;

•	competition in the oil and natural gas industry;

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

---

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

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

---

•

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 produced water 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.

•	Develop Key Infrastructure Systems. By constructing a produced water 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 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.

---

•

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 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.

•

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.

•	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.

•	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.

•	Asset Monetization. The Company periodically evaluates its properties to identify opportunities to monetize assets to fund or accelerate development within its area of focus, 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.

---

(1)	For a reconciliation of PV-10 to Standardized Measure, see “—Proved Reserves.” The Company’s total Standardized Measure was $4.0 billion at December 31, 2013.

(2)	Average daily net production for the month of December 2013.

(3)	Estimated net proved reserves as of December 31, 2013 divided by production for the month of December 2013 annualized.

(4)	Capital expenditures for the year ended December 31, 2013 on an accrual basis.

---

---

•	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.

•	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 Chief Operating Officer.

---

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

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

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

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

•	more than 26 years of practical experience in petroleum engineering and more than 24 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.

•	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, Bachelor of Science Degree in Geology, Master of Science Degree in Geology and Master of Business Administration Degree.

•	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.

---

---

(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, 2013 and 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.

---

(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, 2013, 2012 and 2011. 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:

(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.

---

---

(1)	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 years ended December 31, 2013 and 2012, includes $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.

---

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

---

---

---

---

---

---

---

---

---

•	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.

---

---

---

---

(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.

---

(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.

---

•	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;

•	reductions in oil, natural gas and NGL prices;

•	oil and natural gas property title problems; and

•	market limitations for oil, natural gas and NGLs.

---

•	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;

•	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, 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 acts of force majeure;

•	domestic and foreign governmental regulations and taxation;

•	energy conservation and environmental measures; and

•	the price and availability of alternative fuels.

---

•	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.

---

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

•	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.

---

---

•	the Company’s proved reserves;

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

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

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

---

•	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.

---

---

---

---

---

---

---

---

---

•	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

---

---

---

---

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

---

---

---

---

(1)

Revenues and construction contract expense for the year ended December 31, 2012 have been revised from amounts previously presented. Each has been reduced by approximately $796.3 million to remove Century Plant construction revenue and expense previously recognized during the period and record such amounts directly to the Company’s full cost pool. For further discussion of this revision, see “Note 2 - Restatement and Revision of Previously Issued Financial Statements” to the consolidated financial statements included in Item 8 of this report.

(2)	Includes employee termination benefits.

---

•	Overview;

•	Results by Segment;

•	Consolidated Results of Operations;

•	Liquidity and Capital Resources;

•	Valuation Allowance; and

•	Critical Accounting Policies and Estimates.

•	Drilled 483 wells, excluding salt water disposal wells, in the Mid-Continent area. Mid-Continent properties contributed approximately 17.8 MMBoe, or 52.7%, of the Company’s total production in 2013 compared to approximately 11.0 MMBoe, or 32.9%, in 2012.

•	Gulf of Mexico properties acquired during the second quarter of 2012 contributed production of approximately 9.2 MMBoe, or 27.3% of the Company’s total production in 2013 compared to approximately 7.0 MMBoe, or 20.8% of total production in 2012.

•	Permian Properties divested in February 2013, as discussed below, contributed 3.4% of total production in 2013 compared to 25.8% of total production in 2012.

•	Total production for 2013 was comprised of approximately 42.3% oil, 50.9% natural gas and 6.8% NGLs compared to 47.3% oil, 46.5% natural gas and 6.2% NGLs in 2012.

---

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

---

(1)

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 year ended December 31, 2013. PV-10 differs from Standardized Measure because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of the Gulf Properties. The following table provides a reconciliation of the estimated Standardized Measure attributable to the Gulf Properties to PV-10 attributable to the Gulf Properties as of December 31, 2013 (in thousands):

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

---

---

(1)

Revenues and expenses for the year ended December 31, 2012 have been revised from amounts previously presented. Each has been reduced by approximately $796.3 million to remove Century Plant construction revenue and expense previously recognized during the period and record such amounts directly to the Company’s full cost pool. For further discussion of this revision, see “Note 2 - Restatement and Revision of Previously Issued Financial Statements” to the consolidated financial statements included in Item 8 of this report.

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

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

---

---

---

(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, 2013 are held for sale. Non-operational rig at December 31, 2012 and 2011 was stacked.

---

---

(1)	Includes $199.3 million, $181.2 million and $69.6 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, 2013, 2012 and 2011, respectively.

---

(1)

Includes $157.0 million, $75.4 million and $15.1 million of expenses attributable to noncontrolling interests in consolidated VIEs, after considering the effects of intercompany eliminations, for the years ended December 31, 2013, 2012 and 2011, respectively. The expenses attributable to noncontrolling interest in consolidated VIEs for 2013 include $71.7 million of allocated loss on sale of assets associated with the sale of the Permian Properties.

---

---

---

---

---

---

---

(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.

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	Note 3. Supplemental Cash Flow Information

•	Note 4. Acquisitions and Divestitures

•	Note 8. Property, Plant and Equipment

•	Note 16. Commitments and Contingencies

•	Note 23. Business Segment Information

•	Note 24. Condensed Consolidating Financial Information

•	Note 26. Quarterly Financial Results (Unaudited)(Restated)

---

•	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.

---

(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.

---

(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.

(2)	Pro forma net income, income available 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 and $13.0 million of transaction costs.

---

---

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

---

(1)	Subsequent to the initial public offerings, the Company sold common units of the Royalty Trusts 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 to the Company, and the remaining 50% will be sold with the proceeds distributed to the Royalty Trust unitholders.

---

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

(2)	The Company received incentive distributions from the Mississippian Trust I during the first and second quarters of 2012 and the third quarter of 2011.

---

---

(1)	Includes $3.0 million held by the trustee at December 31, 2013 and 2012 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 at the time of conveyance.

---

---

---

---

(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, 2013 and 2012, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements.

---

(1)	Carrying value is net of $8,843 discount at December 31, 2012.

(2)	Carrying value is net of $5,264 and $5,873 discount at December 31, 2013 and 2012, respectively.

(3)	Carrying value includes a premium, applicable to notes issued in August 2012, of $3,922 and $4,328 at December 31, 2013 and 2012, respectively.

(4)	Carrying value is net of $3,751 and $4,029 discount at December 31, 2013 and 2012, respectively.

---

(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.

(1)	Includes cumulative capitalized interest of approximately $23.4 million and $11.7 million at December 31, 2013 and 2012, respectively.

(2)	Includes cumulative capitalized interest of approximately $4.3 million at both December 31, 2013 and 2012.

(3)	Includes cumulative capitalized interest of approximately $12.0 million and $7.1 million at December 31, 2013 and 2012, respectively.

---

(1)	Includes $45.6 million of pipe inventory costs incurred ($42.6 million in 2013, $2.8 million in 2012 and $0.2 million in 2010 and prior years).

---

(1)	In 2013, the unamortized debt issuance costs associated with the 9.875% Senior Notes due 2016 and 8.0% Senior Notes due 2018 were written off at the time the Company redeemed these notes. See Note 13 for discussion of the senior note redemptions.

---

---

---

---

---

---

---

---

(1)	Represents asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.

(2)

Year ended December 31, 2013 includes $45.3 million for the decommissioning of various platforms, pipeline and associated wells in the Gulf of Mexico and $15.2 million of asset retirement obligations disposed in conjunction with the sale of the Permian Properties. Years ended December 31, 2013 and 2012 include the settlement of plugging and abandonment obligations associated with properties in the Gulf of Mexico. Year ended December 31, 2011 includes amounts related to the Permian Basin and east Texas properties sold during 2011.

(3)	Years ended December 31, 2013 and 2012 include accretion attributable to asset retirement obligations assumed in the acquisitions of oil and natural gas properties in the Gulf of Mexico during the second quarter of 2012.

---

---

---

•	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

---

---

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

---

---

---

---

---

---

(1)	Includes the Company’s deferred tax liability resulting from its investment in the Royalty Trusts. See Note 5 for further discussion of the Royalty Trusts.

---

---

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

---

---

(1)	Includes pro forma ceiling impairment of $441.0 million, including $80.0 million allocated to noncontrolling interest and $361.0 million attributable to SandRidge Energy, Inc., for the year ended December 31, 2013.

---

---

(1)	Income from operations includes impairment of the Company’s goodwill of $235.4 million for the year ended December 31, 2012.

(2)	For the year ended December 31, 2013, loss from operations includes impairment of $11.1 million on certain drilling assets.

(3)	For the years ended December 31, 2013 and 2012, loss from operations includes impairments of the Company’s gas treating plants in west Texas and other midstream assets of $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. Amounts for years ended December 31, 2012 and 2011 have been revised by $50.0 million and $25.0 million, respectively, from amounts previously presented to account for Century Plant construction activity under the full cost method of accounting.

(6)	Exploration and Production and consolidated total revenues and total revenues and expenses have been reduced by $796.3 million from amounts previously presented. See Note 2.

---

---

---

(1)

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

(2)

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

---

---

(1)

Amounts presented as Investment in subsidiaries have been revised to present negative investments in certain subsidiaries, totaling $661.0 million, as liabilities and to present $55.6 million Parent gain on sale of subsidiary with full cost pool assets in 2012 as a reduction to Guarantor full cost pool (property, plant and equipment, net) and a reduction to Parent equity. Gain on sale of subsidiary was previously classified as an adjustment to the consolidated full cost pool through elimination in the condensed consolidating balance sheets. The impact of these revisions was not material to any previously issued financial statements.

(2)

Amounts presented as Investment in subsidiaries have been revised to present negative investments in certain subsidiaries, totaling $147.3 million, as liabilities. Property, plant and equipment, net has been revised to present $55.6 million Parent gain on sale of subsidiary with full cost pool assets in 2012 as a reduction to the Guarantor full cost pool (property, plant and equipment, net) and a reduction to Guarantor equity. Gain on sale of subsidiary was previously classified as an adjustment to the consolidated full cost pool through elimination in the condensed consolidating balance sheets. The impact of these revisions was not material to any previously issued financial statements.

(3)	Guarantor and consolidated accounts payable and accrued expenses include $15.5 million previously classified as other current liabilities. See Note 2.

---

---

(1)	Guarantor and consolidated total revenues, direct operating expenses and total expenses have been reduced by $796.3 million from amounts previously presented. See Note 2.

(2)	Parent and elimination results have been revised to remove amounts previously recorded as Parent gain on sale of subsidiary totaling $55.6 million. The impact of these revisions was not material to any previously issued financial statements.

(3)	Guarantor and elimination other income, net has been revised to remove $79.1 million of Trust unit sales previously recorded as subsidiary earnings on the Parent income statement. The impact of these revisions was not material to any previously issued financial statements.

---

---

---

(1)

Net cash provided by financing activities has been revised to include intercompany (advances) borrowings, net previously included in net cash provided by operating activities. Amounts represent cash flows between the Parent and the Guarantors and Non-Guarantors resulting from the Parent’s centralized treasury activities. The impact of these revisions was not material to any previously issued financial statements.

---

(1)

Net cash provided by financing activities has been revised to include intercompany (advances) borrowings, net previously included in net cash provided by operating activities. Amounts represent cash flows between the Parent and the Guarantors and Non-Guarantors resulting from the Parent’s centralized treasury activities. The impact of these revisions was not material to any previously issued financial statements.

---

(1)	Includes seismic costs of $6.7 million, $15.3 million and $4.9 million for 2013, 2012 and 2011, respectively.

(2)	Includes Company’s share of Century Plant construction costs of $50.0 million and $25.0 million for 2012 and 2011, respectively. See Note 8.

---

(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.

---

---

(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, 2013, 2012 and 2011 as shown in the table below:

---

•	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, 2013, 2012 and 2011 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 $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012 and 2011 respectively.

---

(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 $781.6 million, $952.7 million and $932.8 million attributable to noncontrolling interests at December 31, 2013, 2012, and 2011 respectively.

---

---

(1)

Quarterly results for 2013 have been restated to reflect accrual of the 2013 CO2 shortfall penalty, totaling $32.7 million, on a quarterly basis. Loss from operations, net loss and loss applicable to SandRidge Energy, Inc. common stockholders have increased by approximately $8.0 million, $8.1 million and $8.3 million for the three-month periods ended March 31, 2013, June 30, 2013 and September 30, 2013, respectively, and income from operations, net income and income available to Sandridge Energy, Inc. common stockholders have increased by $24.3 million for the three-month period ended December 31, 2013. Loss applicable per basic and diluted share has increased by approximately $0.02 for each of the three-month periods ended March 31, 2013, June 30, 2013 and September 30, 2013, respectively, and income available per basic and diluted share has increased by approximately $0.05 for the three-month period ended December 31, 2013. See Note 16 for discussion of the related treating agreement.

(2)	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.

(3)	Includes loss (gain) on commodity 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.

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

(5)

(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.

(6)	Total revenues and total expenses for the three-month period ended December 31, 2012 have been reduced by $796.3 million from amounts previously presented. See Note 2.

(7)	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.

(8)	Includes loss (gain) on commodity derivative contracts of $254.6 million, $(669.9) million, $193.5 million and $(19.6) million for the first, second, third and fourth quarters, respectively.

(9)	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.

---

---

---

---

---