Focusing on Liquids-rich Targets in Existing Resource Base. Rockies Division Targets: Shannon, Sussex, Frontier, Three Forks, Middle Bakken, Ft.

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1 August 2013

2 Company Overview Company Snapshot Focusing on Liquids-rich Targets in Existing Resource Base Proved Reserves (12/31/12): 2.0 Tcfe Q Production: 595 MMcfe/d Operated Rigs: 11 Total Net Acres: ~2.2 million Rockies Division Targets: Shannon, Sussex, Frontier, Three Forks, Middle Bakken, Ft. Union Mid-Continent Division Targets: Marmaton, Granite Wash, Hogshooter / Cottage Grove Wash Q2 Production by Division (MMcfe/d) Rockies 233 East Texas 177 Mid-Con 185 Reserves by Category PUD 35% PDNP 1% East Texas Division Active Targets: Cotton Valley Sands Gas Option: Haynesville PDP 64% Samson Rigs 2

3 Corporate Strategy Optimize Capital Program Maximize dollars at the drill bit Focus on prospects with higher liquids content (returns focused drilling program) Reduction in leasehold, geological and geophysical spending Reduce costs and improve efficiencies in the field cost focus drives economic viability of marginal drilling programs Future Drill Bit Inventory Delineate the Granite Wash and Ft. Union positions Actively monitor A&D market for potential acquisitions that provide visibility and inventory Bolt-on to existing core positions with advantaged economics (Mid-Con / East Texas) Protect the Balance Sheet in Short Term Lower exploration risk Well hedged on oil and natural gas for the next months. Program protects near-term capital plan Incremental non-core assets sales divested over $100 million of non-core properties YTD, on track to divest another $200 million by year end Long Term Opportunities to Strengthen Balance Sheet Equity contribution to fund growth from acquisitions or acceleration of delineated inventory Position portfolio for public market access 3

4 Continuing Shift in Production to Liquids Solid Sequential Liquids Growth Natural Gas (Mmcf/d) (3%) Oil +~8% NGL +~11% (MBbls/d) (MBbls/d) Total (MMcfe/d) ~1% 415 Q1'13 Q2'13 0 Q1'13 Q2'13 0 Q1'13 Q2' Q1'13 Q2'13 Q2 13 Production by Commodity Q2 13 Production by Division Oil 16% NGL 13% Rockies 233 (39%) East Texas 177 (30%) Gas 71% Mid-Con 185 (31%) 54.1 Bcfe 595 MMcfe/d 4

5 Drill Bit Focused Capital Program Capital Spend Tracking with Budget Capital spend focused on the drill bit Continuing to focus on liquids-rich drilling projects Shannon (North Tree), Ft. Union, Granite Wash, Marmaton, Bakken and Cotton Valley Sands Multi-well pad drilling across portfolio (in millions) 2013 YTD (1) Drilling and Completion $334 91% Leasehold Geological & Geophysical 12 3% Midstream, Corp & Other 24 6% Total $ % Capitalized Interest 147 Capitalized G&A 16 Total Capital Expenditures $ Budget Midstream & Other 8% LG&G 9% East Texas 13% $758 million Drilling & Completions 83% Rocky Mountains 47% $628 million Mid Continent 40% Drilling & Completion (1) 6ME as of 6/30/2013 5

6 Rocky Mountain Operations Rocky Mountains Snapshot: Net Acreage: ~1,000,000 YE 2012 Proved Reserves: 779 Bcfe Q2 13 Average Daily Production: 233 MMcfe/d Oil 23%; NGL 11%; Gas 66% Current Rig Count: 5 North Dakota Powder River Basin: Williston Basin: Three Forks and Middle Bakken development Q2 13 Production: 4.5 MBoe/d Rig Count: 1 Idaho Wyoming Stacked oil plays targeting: Shannon, Sussex, Muddy, and Frontier Q2 13 Production: 4.0 MBoe/d Rig Count: 2 Green River Basin: Utah Colorado Horizontal program in the Ft. Union Q2 13 Production: 85 MMcfe/d Rig Count: 2 San Juan Basin: Samson Rigs Mature dry gas asset Q2 13 Production: 98 MMcfe/d Diversified Position Across Several Basins with Catalysts for Growth 6

7 CODY SHALE MESAVERDE Powder River Basin Asset Map by Field Targeted Zones North Tree Field LANCE FM. FOX HILLS SS LEWIS SS TEAPOT SS. PARKMAN SS. SUSSEX SS. SHANNON SS. STEELE SH. NIOBRARA SH. "CARLILE SH." WALL CR. SS. FRONTIER FM. Spearhead Ranch Field Hornbuckle Field MOWRY SH. SHELL CREEK SH. MUDDY SS. THERMOPOLIS SH. *Strat column from USGS Scott Field Samson Rigs Extensive Acreage Position Anchored by Shannon Development with Exploration Upside 7

8 Powder River Basin North Tree Field Overview Rig Count: Currently operating 2 rigs drilling multi-well pads targeting the Shannon interval Development Map North Tree (Shannon) Activity: Strategically drilled and completed 7 horizontal wells testing and delineating North Tree Field 7 well average Max IP of 1,440 BOPD and average IP30 of 429 BOPD (range BOPD) Next Steps Begin Development: 2H 2013 Plan: Started July 1 st. 12 HZ wells from 4 pads using a combination of short and long reach laterals 2014 Development 2014 Plan: 24 HZ wells from 11 pads using a combination of short and long reach laterals Full Scale Potential North Tree Field 17,000 net acres, 28 additional locations on 320 acre spacing Estimated Well Profile (Short/Long): D&C: $6.5 / $8.2 MM EUR: 350 / 580 MBOE 2013 Development IRR: ~20% / ~38% at 6/28 Strip (1) (1) 6/28 Strip 5 Years to Flat: Gas $4.26; Oil $ Established Repeatability; 2013 Begins Full Scale Development Samson Rigs Producing Wells Planned Drilling 8

9 Powder River Basin Sussex Overview Sussex by Field Rig Count: Currently no active rigs. Two rigs shared between Powder River and Green River due to wildlife stipulations and permit lead time. Two rigs move from Green River back to Powder River to resume Sussex program in January 2014 Spearhead Ranch Duck Creek Federal (Sussex completion) IP 30: 330+ BOPD Summary: ~60,000 net acres 55 HZ producing Sussex wells in Hornbuckle, Spearhead, and Scott Fields Q2 13 Production: ~2,800 Boe/d Next Steps Development Dependent on Permitting: 25 potential locations in 2014 Continuing to delineate in Scott Field Additional locations dependent on further drilling results and defining down spacing potential Additional Exploration: Muddy Frontier Hornbuckle Scott Samson Rigs Producing Wells Promising Economics in Delineated Fields 9

10 Bakken Ambrose Field Overview Ambrose Field Asset Map Rig Count: Plan to operate 1 rig through 2014 drilling Middle Bakken and Three Forks Williston Basin Snapshot: ~69,000 net acres in Divide County ~29,000 Operated Q2 13 Production ~4,500 Boe/d Next Steps: Expect to drill 33 gross operated wells in 2013 and ~25 gross operated wells in 2014 Continued focus on cost reductions; Average CWC declined from ~$9.0 MM in 2010 to ~$7.0 MM in 2012 Estimated Well Profile: Working Interest: ~43% D&C: $7.0 MM TVD: ~8,000 ; Lateral: 10,000 EUR: 394 MBOE IRR: ~15-20% at $85 WTI AMBROSE FIELD Samson Rigs Operated Acreage Non Operated Acreage Solid Oil-Weighted Position 10

11 Bakken Performance Benchmarking Performance Over Time Performance vs. Peers Average Completed Well Cost by Quarter (1) Average Feet per Day by Operator* 36% reduction since Q Top Quartile Completed Well Cost performance has improved substantially over the last two years driven by a strong focus on operational improvements and efficiency Samson ranks in the top quartile in drilling feet per day relative to other operators in the Bakken Continuous Improvement Support Program Economics * Benchmarking data sourced from Smith Bits records for Bakken horizontal wells with TD > 17,000 spud between 1/1/2012 and 3/14/2013 (1) Several of the wells drilled and completed in Q3 / Q were shorter laterals which cost approximately $300,000 - $500,000 less than typical 9,500 laterals 11

12 Green River Basin Ft. Union Overview Asset Map Summary: ~32,000 net acres Currently 16 vertical and 4 horizontal producing Ft Union wells Q2 13 Production: 47 MMcfe/d Activity to Date: Drilled first HZ well during the drill window followed by 3 horizontals during the drill window First four HZ wells yielding promising results; drilling costs were higher than expected due to difficult down hole complications Average IP Rate for HZ Wells: 16.4 MMCFD & 346 BOPD Liquids Rich Gas: WH Btu Factor: WH NGL Yield: GPM WH Condensate Yield: 7 30 B/MM Barricade 14-1H First Sales: 1/2012 Peak IP Rate: 14.4 MMCFD & 286 BOPD Cum Gas: 3,244 MMCF Cum Oil: 88.5MBO Barricade 21-11N1MH First Sales: 1/2013 Peak IP Rate: 5.3 MMCFD & 211 BOPD Cum Gas: 617 MMCF Cum Oil: 9.5 MBO Sweetwater Producing Middle HZ Well Producing Lower HZ Well Barricade 41-6 S1LH First Sales: 2/2013 Peak IP Rate: 21.5 MMCFD & 387 BOPD Cum Gas: 2,012 MMCF Cum Oil: 30.2 MBO Barricade 41-6 S1MH First Sales: 2/2013 Peak IP Rate: 24.2 MMCFD & 500 BOPD Cum Gas: 2,657 MMCF Cum Oil: 78.4 MBO Significant Resource Potential Delineation Continues 12

13 Green River Basin Ft. Union Overview Drilling Plan Rig Count: 2 seasonal rigs (August through February drilling window due to wildlife stipulations) Drilling Plan: Drill and complete 6 HZ wells Test spacing & delineate to the Northeast (higher liquids content expected) Test stacked lateral concept Target lower drilling costs Unrisked Resource Potential: 574 BCFe based on 75 wells and 1,800 spacing Additional Upside Catalysts: Potential for stacked laterals Optimize cost through continuous drilling program Estimated Well Profile: D&C: ~$14 MM EUR: ~1,320 MBOE IRR: ~28% at 6/28 Strip (1) Total Pay Interval ~ 900 Upper Middle Lower Sweetwater Existing HZ Wells Lower Target Middle Target Upper Target (1) 6/28 Strip 5 Years to Flat: Gas $4.26; Oil $85.29 Drilling Program Focused on Maximizing Project Potential 13

14 Mid-Continent Operations Focus Areas Asset Map Upper Granite Wash: Two rigs testing multi-well pad development to drive down costs and delineate play potential for significant drilling inventory Marmaton: Running two rig program adjacent to successful industry activity Mississippi Lime: Completed first four Mississippi Lime wells; initial results appear encouraging. Continue to further delineate this play with potential for additional acreage / scale Samson Rigs Net Acreage: ~574,000 Proved Reserves: 627 Bcfe Q2 13 Average Daily Production : 185 MMcfe/d Oil 17%; NGL 18%; Gas 65% Current Rig Count: 4 Legacy Position Continues to Yield New Opportunities 14

15 Anadarko Shelf Granite Wash Texas Oklahoma Overview Granite Wash Asset Map Rig Count: Currently operating 2 rigs drilling multiwell pads targeting Granite Wash stacked pay Acreage: ~63,000 net acres across Hemphill, Wheeler and Roberts Counties Next Steps: Potential for ~200 locations 2H 2013 Plan: Test three pads with 2 4 stacked laterals each Hefley 4 Well Pad targeting four different stacked GW zones Lister 3 Well Pad targeting three different stacked GW zones Reduce Well Costs: Average single well D&C $7.2 MM; Target $6.5 MM via pad drilling and completion optimization Inventory Upside: Validating returns on multi well pads in the Granite Wash will provide 50+ potential pad locations Estimated Well Profile: D&C: ~$6.5 MM EUR: ~600 MBOE IRR: ~18% at 6/28 Strip (1) (1) 6/28 Strip 5 Years to Flat: Gas $4.26; Oil $85.29 Pounds 2 Well Pad Stacked GW Potential Hefley 4 Well Pad Lister 3 Well Pad 2013 Planned Drilling Samson Rigs Potential Pad Drilling Locations Transition to Pad Drilling Creates Potential for Long-Term Visibility 15

16 Marmaton Overview Rig Count: Currently operating 2 rigs in Black Kettle; both rigs will remain in area for balance of 2013 Activity Summary: Drilled 4 wells YTD; 12 wells planned for 2013 Key Goals and Next Steps: Reduce drill days / cost ROGER MILLS Asset Map Black Kettle Leon 3-10H (2 Well Pad) Maxon 3-13H Test down dip and infill spacing - Success could yield an additional 30+ locations Estimated Well Profile: Working Interest: ~50% D&C: $8.8 MM TVD: 11,300; Lateral 5,000 EUR: 650 MMBOE IRR: ~20% at 6/28 Nymex strip (1) Current Industry Activity: 15 wells drilled to date; current area rig count - 2 Samson rigs, 2 Apache rigs and 1 Chesapeake rig Samson Rigs Key Wells Planned Drilling Maxon 2-13H D&C $8.8MM IP 30: 1,300 BOPD; 6.4 MMCFD wet gas EUR: ~815 BOE (1) 6/28 Strip 5 Years to Flat: Gas $4.26 ; Oil $85.29 Opportunistic Program with the Potential to Add Scale 16

17 East Texas Operations Overview Asset Map E TX / NW LA Liquids-rich and dry gas producing properties in East Texas and North Louisiana with focus on liquids-rich gas drilling Cotton Valley: Liquids-rich horizontal play encouraging well results support continued development Haynesville/Bossier: No activity currently, ~116,000 net acres HBP provides exposure to potential for future gas price uplift Net Acreage: ~380,000 Proved Reserves: 608 Bcfe Q2 13 Average Daily Production : 177 MMcfe/d Oil 5%; NGL 10%; Gas 85% Current Rig Count: 2 Samson Rigs 17

18 East Texas Cotton Valley Cotton Valley Overview Focus Area - Southeast Carthage Field Rig Count: Operating 2 rigs in SE Carthage Field; 7 and 2 well pad in progress Cotton Valley Snapshot: Acreage: ~31,000 net acres Primary Targets: CV C & B Sands Twomey Heirs #3H (Cotton Valley C Completion) 30 Day IP - 7,280 Mcfd & 454 BOPD Secondary Target: CV Taylor Q2 13 Production: 78 MMcfe/d Next Steps: Werner-Caraway (7 Well Pad) Continue focusing on SE Carthage liquids rich intervals; 29 locations remaining (as of 7/1) D&C down from $7 MM to less than $6 MM, best in class $5 MM well in Q1 13 Estimated Well Profile CV C & B Sands: Working Interest: ~66% D&C: ~$ MM 3-Stream EUR: Bcfe IRR of ~30%- ~50% at 6/28 Strip (1) at ~5.5 MM targeted D&C (1) 6/28 Strip 5 Years to Flat: Gas $4.26; Oil $85.29 Transition to Pad Drilling and Focus on Liquids-Rich Intervals has Led to Solid Returns 2013 Remaining C Sand Target 2013 Remaining B Sand Target Samson Rigs 18

19 Cotton Valley Drilling Performance Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Well 7 Well 8 Well 9 Well 10 Well 11 Well 12 Well 13 Well 14 Well 15 Well 16 Performance Over Time Performance vs. Peers Average Completed Well Cost by Spud Date Average Feet per Day by Operator* $9, $8, $7,000 $6,000 $6.5 MM Average $5.8 MM Average $5, $4, $3, $2,000 0 SAMSON LAST 7 Peer 1 SAMSON Peer 2 Peer 3 Peer 4 Since Q4 12, HZ Completed Well Cost performance at SE Carthage Field has improved on average by ~$700,000 Samson s last 7 wells continue to demonstrate a focus on operational efficiencies Continuous Improvement is Driving Strong Results Relative to Peers * Benchmarking data sourced from Smith Bits records for CVS horizontal wells in Panola County, TX. Spud between 1/1/2012 and 3/14/

20 Financial Strategy Committed to a Strong and Stable Capitalization Profile Target long-term leverage below 3.0x Maintain financial flexibility to execute on near-term capital plan Focus on maintaining solid liquidity position ~$1.5 billion as of 8/1/13 Access equity capital to delever with growth focused acquisition Capital Spending Decisions Driven by Risked Discounted Cash Flow Target minimum of 20% IRR for capital projects Project level cash flow generation and sale of non-core assets will fund development programs Continue to Improve Operating Margins by Deploying Capital to Highest Return Opportunities Over 90% of the 2013 drilling budget dedicated to oil / liquids-rich projects Maximize capital to drill bit Hedging Strategy Focused on De-Risking Price for Substantial Portion of the Forecasted Production Target 50% to 75% of rolling 18 to 24 month production Maintain a diversified group of hedge counterparties Opportunistically hedge in times of dislocation for longer periods 20

21 Debt Maturities and Current Liquidity Debt Maturity Profile and Liquidity ($MM) 2020 $2, $1, $302 $1,478 RBL Capacity: $1.78B $0 $500 $1,000 $1,500 $2,000 $2,500 Revolver - Borrowings Revolver - Availability Second Lien Senior Notes (1) As of August 1, 2013, we had $302 million borrowed under our RBL which results in revolver availability of $1.48 billion Sufficient liquidity No near-term maturities (1) Revolver borrowings and availability as of 8/1/2013 (excludes outstanding letters of credit) 21

22 Current Hedge Position As of August 16, 2013 Gas Swaps Oil Swaps NGL Swaps Year MMBtu/d Swap Price ,000 $ ,000 $ ,000 $ ,000 $ ,000 $3.92 Year Bbls/d Swap Price ,500 $ ,500 $ ,500 $90.91 Year Bbls/d Swap Price ,250 $ ,500 $34.65 Hedging strategy focused on protecting cash flow from expected future production 2013: August - December 22

23 Reserve Summary NSAI SEC Reserve Report 12/31/2012 Oil (MMBbl) NGL (MMBbl) Gas (Bcf) Total (Bcfe) PV-10 ($MM) % Liquids PDP ,021 1,297 $1,874 21% PDNP % PUD % Total ,323 2,014 $2,740 34% SEC Realized Pricing at December 31, 2012 Oil $84.72; Gas $2.272; NGLs $38.12 Using current strip pricing, we add over $1.0 billion of incremental value PDP Reserves by Product PUD Reserves by Product Total Proved Reserves by Product Gas 79% Oil 11% NGLs 10% Gas 41% NGLs 21% Oil 38% Gas 66% Oil 20% NGLs 14% 1,308 Bcfe 21% Liquids 706 Bcfe 59% Liquids 2,014 Bcfe 34% Liquids 23

24 Adjusted EBITDA Reconciliation Three Months Three Months Twelve Months Ended Ended Ended March 31, 2013 June 30, 2013 June 30, 2013 (revised) Net income (loss) $ (58,229) $ 83,044 $ (1,514,074) Interest expense, net - - $ - Provision (benefit) for income taxes (32,385) 46,032 $ (797,126) Depreciation, depletion and amortization (a) 129, ,967 $ 618,208 EBITDA $ 38,449 $ 257,043 $ (1,692,992) Adjustment for unrealized hedging losses (gains) 64,075 (82,012) 109,300 Adjustment for non-cash stock compensation expense (b) 4,961 6,123 37,850 Adjustment for fees paid to co-investors (c) 5,250 5,250 20,500 Adjustment for fees paid for public company compliance 1, ,841 Loss on sale of other property and equipment 3,005-3,005 Adjustment for restructuring expenses (d) ,643 Adjustment for bad debt expense Provision to reduce carrying value of oil and gas properties 69,269 11,061 2,242,447 Unusual or non-recurring charges described in credit agreement 2,812 5,764 8,576 Adjusted EBITDA $ 189,530 $ 203,797 $ 778,232 (a) Includes depreciation, depletion and amortization of oil and gas properties and depreciation and amortization of other property and equipment. (b) Stock compensation expense recognized in earnings, net of capitalization (c) Quarterly management fee (d) Total expenses incurred in Q4 related to the restructuring (including the RIF) 24

25 Forward Looking Statements This presentation contains forward-looking statements, which reflect our expectations regarding our future growth, results of operations, operational and financial performance, business prospects and opportunities and future events. Words such as, but not limited to, anticipate, continue, estimate, expect, may, might, will, project, should, believe, intend, continue, could, plan, predict and negatives of these words and similar expressions are intended to identify forward-looking statements. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this presentation are forward-looking statements. These statements are based on, but not limited to, management s assessment of such factors as the condition of our industry and the competitive environment. These assessments could prove inaccurate. All forward-looking statements involve risks and uncertainties. The occurrence of the events described and the achievement of the expected results depend on many events, some or all of which are not predictable or within our control. Although the forward-looking statements contained in this presentation reflect our current beliefs based upon information currently available to us and upon assumptions which we believe to be reasonable, actual results may differ materially from expected results. Factors that may cause actual results to differ from expected results include, among others: fluctuations in natural gas and oil prices; uncertainties relating to the drilling of our wells; estimates of our reserves, future net revenues and PV-10; the timing and amount of future production of natural gas and oil; our financial strategy, liquidity and capital required for our development program; changes in the availability and cost of capital; proved and unproved drilling locations and future drilling plans; production rates relating to our natural gas and oil reserves; our ability to capitalize on opportunistic acquisitions of natural gas and oil reserves; write-downs and decline in value of undeveloped acreage if drilling results are unsuccessful; recording of certain non-cash asset write-downs in the future; liability claims as a result of our natural gas and oil operations; actions taken or non-performance by third parties, including other working interest owners, contractors, operators, processors, transporters and customers; competitive conditions in our industry; the use and development of new industry technologies; our ability to recruit and retain qualified personnel necessary to operate our business; our ability to consummate and successfully integrate acquisitions and our ability to realize any cost savings and other synergies from any acquisition; the performance of our information technology systems; general economic and business conditions; our hedging strategy and results; the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; the effects of derivatives reform legislation; elimination of certain natural gas and oil exploration and development federal and state tax deductions and credits; compliance with existing and future FERC regulation; the effects of existing or future litigation; and plans, objectives, expectations and intentions contained in this presentation that are not historical.

26 We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital and the timing of development expenditures. Reserve engineering is a process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this presentation are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this presentation.