2. Ran Tubing, Flowing up Annulus Longhurst 3H-34

3. Observations Momentum increased dramatically in last 18 months SandRidge continues to lead the way (47% of 2012 Capex of $1.8 billion) Liquid-weighted (~63%) with NGL component Conventional carbonate reservoir: 3,000 – 6,000 ft vertical depths Low well costs (~$3.5 million per location) Low and improving drill times (currently ~24 days) Low pressure rigs, fracs and completions (equipment availability) Infrastructure already in place Repeatability IRRs ~100%

4. Mississippian vs. Bakken and Bone Spring Shale “Tudor, Pickering, Holt & Co. Securities Inc. analysts observed: ‘Horizontal moves to conventional activity: If it’s good for the goose, it’s good for the gander. Horizontal drilling, combined with fracing – makes shales productive. So, why shouldn’t that make conventional reservoirs productive? Answer: It should’ “ Nissa Darbonne - Oil & Gas Investor

5.  Obtained original property set 4Q 2009  Increased through additional leasing  Spud first Mississippian well in June 2010  Began 2 rig program in July 2010  Current 3 rig line, moving to 4  Drilling our ~50 th Mississippian horizontal

6.  ~85,000 net acres in Mississippian  Protected through term and drilling schedule  Short spud to production time frame  Flat topography in pro-oilfield area  ~600 potential locations  PV10 of P3 reserves in excess of $1.75 billion

7. Source: 2012 SD Investor Presentation

8.  Low cost of ~$3.5 million/well  Mostly oil and liquids production  High permeability, carbonate reservoir  No seismic needed; ~17,000 vertical Mississippian data points  working off mud logs  Industry average peak 30-day production ~300 boepd  Rigs are abundant and only require ~1,000 HP  ~ 500 horizontal well data points currently, rig count increasing dramatically  Average lateral length of 3,000-4,000 feet  Fracturing with fresh water and acid  ~One fracture stage per 400-500 feet of lateral  10,000-12,000 Hydraulic HP pressure pumping for completions, in contrast to 40,000 needed in deeper, tighter unconventional plays  Ottawa sand proppant is plentiful  IRRs ~ 100% Sources: SandRidge Energy April 2011 Investor Presentation and Oil and Gas Investor, April 2011.

9.  Vertical Mississippian wells provide control  Limestone, Dolomite & Chert  10-15% porosity  35-65% water saturation  Stacked progradational porosity wedges  Better porosity areas show vugs and dolomite rhomb development  Monoclinal dip

10. Breakeven play comparison to achieve 10% IRR Liquids content Note: Liquids includes oil and NGLs. Excludes primarily gas plays (i.e. Haynesville and Marcellus). Source:Wall street research, SandRidge investor presentation and EOG resources investor presentation. And Eagle internal data.

11. The area’s legacy production has significant existing available infrastructure Extensive infrastructure

12. Takeaways Horizontal drilling effectively connects existing porosity wedges Exceptional horizontal well performance across the play by a variety of operators Single well economic summary

13. 513 MBOE (12/31)

14.  Average peak 30 day production across all 32 wells is 658 BOE/day.  Average peak 30 day production across wells included in the type curve is 705 BOE/day.  Average peak 30 day production for wells with less than 12 months production is 803 BOE/day.

16. DRY GAS Dry Gas (BOe)OilNGLBOETYPE WELL MOST RECENT < 12 Months Production Ames 3H-272115.0352.5492.0172.51017.0 Avard 1H-301649.0274.8271.8134.5681.1 Avard 1H-312054.4342.4571.9167.61081.9 Baker 1H-332289.8381.6313.0186.8881.4 Brockman 1-H620.4103.4101.650.6255.6 Buckles 1H-31434.7239.1175.0117.0531.1 Buckles 1H-92044.5340.8200.0166.8707.5 Edwards 1H-36864.3144.1431.070.5645.6 Glass 1H-181352.2225.4394.3110.3730.0 Glass 1H-72153.8359.0319.9175.7854.5 Johnson 1H-13353.959.0264.828.9352.7 Joy 1H-361415.6235.9302.7115.5654.1 Keltner 1H-17463.977.3148.837.8264.0 Leeper 1H-263172.5528.8195.0258.8982.5 Leslie 1H-2956.0159.346.578.0283.8 Leslie 1H-28639.4106.6157.652.2316.3 Leslie 1H-331626.4271.1405.7132.7809.4 Lohmann 1H-202327.2387.9152.8189.8730.4 Lohmann 1H-291974.0329.0180.0161.0670.0 Lohmann 1H-81395.9232.7206.0113.9552.5 Lone Eagle 1-81033.5172.3275.484.3531.9 Longhurst 3H-342997.0499.51874.0244.42617.9 Mary Beth 1-H564.794.1423.146.1563.3 Page 2H-26690.9115.24.056.4175.5 Percival 1H-6775.5129.3190.063.3382.5 Reed 1H-101121.0186.8360.491.4638.6 Sharp 1H-12795.2132.5269.364.9466.7 Stelling 1H-233898.7649.8412.8318.01380.6 Thorp 1H-61316.9219.5104.0107.4430.9 Wenniger #1341.256.975.227.8159.9 Wessels 1H-26348.358.052.228.4138.6 Zahorsky 1H-8987.0164.5310.080.5555.0 Average:1430.4238.4302.5116.7657.6705.2803.3 Wells:32 2919

17. Ran Tubing, Flowing up Annulus Longhurst 3H-34

18.  IP’s of Wells in Last 100 Days  Gas Volumes are Wet Gas  Berry 1H-32290 BO, 2.2 MMCF (10 Day)  Baker 1H-33313 BO, 3.2 MMCF (30 Day)  Zahorsky 1H-8 310 BO, 1.4 MMCF (30 Day)  Percival 1H-6190 BO, 1.1 MMCF (30 Day)  Ames 3H-27443 BO, 2.9 MMCF (45 Day) 492 BO, 3.0 MMCF (30 Day)  Leeper 1H-26190 BO, 4.1 MMCF (45 Day) 195 BO, 4.5 MMCF (30 Day)  Lohmann 1H-29115 BO, 1.8 MMCF (80 Day) 180 BO, 2.8 MMCF (30 Day)  Buckles 1H-9165 BO, 2.8MMCF (100 Day) 200 BO, 2.9 MMCF (30 Day)

19.  Evolution of current wellbore design.  Wenniger #1 – Re-Entry of Hunton wellbore  Brockman 1-H – 5 ½” long string  Leslie 1H-2 – 7” production – 4.5” liner  Evolution of targeting  Originally targeted the top 100’ of the Mississippian  Resulted in high water production, lower IP’s than expected  Currently targeting the top 60’  Better IP’s  Lower water production

20. Horizontal locations on top of thousands of historical vertical wells Drilling days improve with experience Mississippian – Drilling times trend lower Source:SandRidge and Continental Resources investor presentation. 30 Days 22 Days

21.  500’ Stages (~425’ GPI)  Original design was too large  3,500 bbls Water  85,000# Sand  200 bbls 15% HCl  Larger design combined with lower targeting resulted in higher water production and lower reserves.  Current design  1,600 bbls Water  20,000# 30/50 Sand  575 bbls 15% HCl  100bpm  Average treating pressure 3500psi  Better cleanup near wellbore  Natural permeability  Can re-stimulate to restore production.  1 re-complete to date: ~300 MBOe added reserves at a cost of ~$1.40/BOe  Drill out with Coiled Tubing

23.  Infrastructure  Designed for Hunton dewatering  Artificial Lift  Initially running ESPs  High volume pumps  Quick recovery of frac load  Lowers fluid levels quickly  VSDs allow flexibility  Adaptable to individual wells

24.  Highest average IP’s in the Mississippian trend  Longhurst 3H-34: ~3,000 BOe/d (24hr)  30 Day: 1874 BO, 4.251 MMCF  60 Day: 1833 BO, 4.453 MMCF  210 Day: 1129 BO, 2.875 MMCF  To Date: 240+ MBO, 0.610+ BCF  IP’s based on Wet Gas  Sharp 1H-12: ~2,600 BOe/d (24hr)  Avard 1H-31: ~1,900 BOe/d (24hr)  Stelling 1H-23~1,700 BOe/d (24hr)  Avard 1H-30~1,900 BOe/d (24hr)  ~735 BOe/d Avg 30 day IP, leveling off at ~250BOe/d  Type Well = 513,300 BOe EUR  Liquid Content = 63% (45% Crude)  LOE = $2.06/BOe  F & D = $6.81/BOe

25. Conclusions IRRs exceeding other liquids-rich plays IRRs driven by low drilling and service costs coupled with attractive oil mix and EURs Ample available infrastructure and equipment Improving results and costs will drive economics higher; EURs have improved with recent results Rate of return Source:SandRidge investor presentation and Eagle internal data.