July 2013

2012 2013 2014+

The Path to Future Growth

Focused on building a solid foundation for future growth and value creation

Enhanced rigor applied to capital allocation – return based approach

Cost control initiatives

Improved liquidity with Term Loan

Initiated Enterprise Resource Planning (SAP)

Divested non-core assets

New leadership

Operational excellence

Focusing on core areas

Testing new plays in core areas

Divesting non-core assets

Monitoring M&A market for acquisition opportunities

Focus on returns, growth and portfolio optimization

Transition new play testing to development

Achieve balanced commodity mix

Delever balance sheet and maintain significant financial flexibility

2

Extensive Acreage Inventory Positions

Company for Operational

Flexibility

Focus on Cash Returns

Over 90% of capex focused on drilling oil / liquids-weighted drilling projects

Maintaining ~ 50% liquids target by 2016

Implementing company wide initiatives to enhance well economics through lower cost model

Large, Diversified Asset Base

Significant operational scale in core areas – Rockies, Mid-Continent and East Texas

Extensive current drilling inventory of over 4,500 identified locations provides visibility to future growth

opportunities ~82% of which are oil and liquids rich

Diversified production across multiple regions – ownership interests in 7,640 gross wells (3,380 net wells)

Over 2.6 million(1) net acres concentrated in our three core areas with ~60% HBP

Diversity of the asset base and significant HBP position in several of our core areas provides flexibility

to focus on highest rate of return projects

Operate 67% of net production which allows more effective management of timing and costs

Company Highlights

Experienced Management and

Technical Team

Senior management team has extensive expertise in the oil and natural gas industry – senior

management has on average 25+ years of industry experience

Technical professionals have an average of 20+ years industry experience

Solid Financial Flexibility

As of 6/30/2013, over $1.42 billion of liquidity with access to equity for growth focused initiatives

Proactively hedge to protect cash flows and capital program

3 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres and 2013 Permian divestitures expected to close in aggregate by Q3 2013

Oil 14%

NGL 12%

Gas 74%

PDNP 1%

PDP 64%

PUD 35%

Significant Upside Potential in Existing Resource Base Snapshot

Headquarters: Tulsa, OK

Total net acres: ~2.63 million (1)

2013 Q1 Avg Daily Production

12/31/12 Reserves

591 Mmcfe/d

Large Asset Base

2,014 Bcfe

Rockies (oil, liquids & gas plays)

Net acreage: ~1,180,000(1)

Targets: Ft. Union, Sussex, Shannon,

Frontier, Three Forks, Middle Bakken

Mid-Continent (liquids rich gas plays)

Net acreage: ~680,000

Targets: Hogshooter, Granite Wash,

Cottage Grove, Marmaton

(1) Pro forma 2012 Bakken divestiture of 147,000 net acres and 2013 Permian divestitures expected to close in aggregate by Q3 2013

Active Rigs as of June 2013

East Texas/ N. Louisiana (oil, liquids & gas plays)

Net acreage: 450,000

Targets: Cotton Valley, Haynesville

4

Oil 14%

NGL 12%

Gas 74%

Q1 2013 Summary Review

(1) Net of non-cash equity compensation

Q1’13 Production by Product

53.2 Bcfe

Q1’13 Avg Daily Production by Division

Key Metrics – Q1 2013 compared to Q1 2012

Three Months Ended March 31,

2013 2012 Change

Revenue ($ in millions)

Gas and NGL $150 $138 9%

Oil 113 126 (10%)

Derivatives (50) 20 NM

Total Revenue $213 $284 (25%)

Operating Expense ($ per Mcfe)

LOE $0.94 $0.90 4%

Production/Ad Val Tax $0.35 $0.47 (26%)

DD&A $2.43 $2.59 (6%)

G&A(1) $0.50 $0.45 11%

Pricing

Before the effects of hedges

Gas ($ per Mcf) $3.46 $2.93 18%

Oil ($ per barrel) $82.23 $98.00 (16%)

Combined Production ($ per Mcfe) $5.09 $4.82 6%

After the effects of hedges

Gas ($ per Mcf) $3.83 $3.78 1%

Oil ($ per barrel) $80.67 $87.16 (7%)

Combined Production ($ per Mcfe) $5.37 $5.29 2%

Capital Expenditures

Drilling and Completion $190 $368 (48%)

Leasehold Geological & Geophysical 5 38 (87%)

Midstream, Corp & Other 13 17 (29%)

Total $208 $423 (50%)

Capitalized Interest 127 40 235%

Total Capital Expenditures $335 $463 (23%)

591 Mmcfe/d

East Texas 195

(33%)

Mid-Con 180

(30%)

Rockies 216

(37%)

5

Returns Focused Development Approach

Ft. Union Bakken Sussex Shannon Upper GW Hogshooter

/Cottage Grove

Cotton Valley B & C Sands

Marmaton

EURs (MBOE)

1,357 425 346 353 735 357 1,218 720

% Liquids 55% 87% 94% 91% 32% 67% 33% 42%

D&C Cost ($mm)

$13.5 $7.4 $6.5 $7.4 $6.8 $7.3 $6.5 $9.2

F&D Cost ($/Boe)

$9.95 $17.38 $18.79 $20.95 $9.25 $20.47 $5.34 $12.78

IRRs ~30% >20% >20% >20% >20% >20% ~33% >20%

Expected Development Well Economics

6

Liquids-Focused Capital Program

Total Drilling &

Completions 83%

Leasehold, Geological & Geophysical

9%

Facilities 8%

2013 Capital Budget

$758 million

(1) Drilling window limited by wildlife stipulations, plan to operate 2 rigs during the Aug 2013 – Feb 2014 drilling window

Region 2013 Budget

($ in MM) Basin/Field Targeted Plays / Formations Current

Rig Count

Rockies $290-300 Powder River Basin Shannon 2

Green River Basin Ft. Union 2(1)

Bakken Middle Bakken, Three Forks 2

Mid-Con $250-255 Anadarko Basin Hogshooter, Marmaton 2

Granite Wash 2

East Texas $75-80 SE Carthage Cotton Valley Sands (“C” and “B”) 2

Total $615-635 10-12

Q1 2013 Capital Spend vs. 2013 Budget

2013 Capital Budget

% of Budget

Actual Q1' 13

% of Q1'13 Actuals (in millions)

Drilling and Completion $628 83% $190 91%

Leasehold, geological and geophysical 70 9% 5 2%

Midstream, corporate and other 60 8% 13 6%

Total $758 $208

7

Overview

Focus on oil and liquids rich properties in four major producing basins:

Powder River Basin: Stacked oil plays targeting the oil zones: Shannon, Sussex, Muddy, and Frontier

Green River Basin: Horizontal program in the Ft. Union

Williston Basin: Three Forks and Middle Bakken development

San Juan Basin: Mature dry gas asset

Rocky Mountain Operations Asset Map

Net Acreage: ~1,180,000(1)

Proved Reserves: 779 Bcfe

Q1’13 Average Daily Production: 216 MMcfe/d

Oil 23%; NGL 8%; Gas 69%

Current Rig Count: 4

(1) Pro forma 2012 Bakken divestiture of 147,000 net acres

Active Rigs as of June 2013

8

2013 plan sets the stage for additional development drilling in 2014

Currently, Samson has 275,000 acres across the

region and plans to operate two horizontal rigs this

year

Continue development of Sussex at Hornbuckle

Begin full scale development of North Tree

Monitor industry activity in horizontal Frontier and

Muddy programs for future exploration potential

Powder River Basin

Powder River Basin Highlights / Plans Asset Map by Field

Core Position with Multiple Oil Targets

North Tree

Hornbuckle

Scott

Spearhead Ranch

DF Nebraska 24-20 43-76H (Shannon completion) Max IP: 1000+ BOPD

TCR Kentucky Fee 24-22 43-76bh (Shannon completion)

Duck Creek Federal 14-29 (Sussex completion)

Active Rigs as of June 2013

Key Wells

9

Total acreage position of 37,500 acres between Barricade and Endurance units

Identified 93 gross horizontal locations, with potential for 2 or 3 stacked laterals per location

4 horizontals wells currently producing

Plan to operate two rigs during the Aug 2013 - Feb 2014 drilling window

Plan to drill 6 horizontal wells

Drilling window limited by wildlife stipulations which restricts year round operations

Pursuing year round drilling options

Potential for significant production from field

Green River Basin – Ft. Union

Ft. Union Highlights

Liquids Rich Gas Development

Asset Map

Horizontal Wells Drilled

Barricade 14-1H First Sales 1/2012 IP Rate 14.4 MMcfd & 286 BOPD Cum Gas 2,912 MMcf Cum Oil 80 MBO

Sweetwater

10

Cost initiatives driving program economics

Bakken – Ambrose Field

Bakken Highlights Asset Map: Ambrose Focus Area

Ambrose Area: ~ 75,000 acres

Currently operating two rigs

Plan to drill ~40 gross operated wells in

2013

Continued focus on cost savings

through pad drilling, cycle time

initiatives and optimal frac designs

Industry leading cycle times

Initial phase of the Oneok Gas Gathering

System is in service

Developing Three Forks and Middle Bakken

Active Rigs as of June 2013

Nomad 0607-1TFH (Three Forks Completion)

30 Day IP – 450+ BOPD

Thomte 0508-03TFH (Middle Bakken Completion)

30 Day IP – 725+ BOPD

Border Farms 3130 2TFH (Three Forks Completion)

30 Day IP – 575+ BOPD

Key Wells

11

4,153 gross producing wells from 25+ established productive intervals across the Anadarko, Arkoma and Ardmore basins

Current focus areas include:

Hogshooter / Cottage Grove Wash: Samson has drilled and completed several Hogshooter and Cottage Grove Wash wells with results exceeding 50% IRR’s on a program basis. Currently operating two rigs in the play

Upper Granite Wash: Testing multi-well pad development to drive down costs and delineate play potential

Marmaton: Running two rig program adjacent to successful industry activity.

Mississippi Lime: Completed first three Mississippi Lime wells which exceeded expectations. Samson will further delineate this play and expects future activity in this play along with other oil plays across the Mid- Continent Division

Mid-Continent Operations

Overview Asset Map

Net Acreage: ~684,000

Proved Reserves: 627.4 Bcfe

Q1’13 Average Daily Production: 180 MMcfe/d

Oil 14%; NGL 19%; Gas 67%

Current Rig Count: 4

Active Rigs as of June 2013

12

Davis 65-21H (GW Purple) IP24: 11.5 MMcfd, 550 BOPD

Anadarko Shelf Team

Huff 32-8H (Hogshooter) IP 24: 5.0 MMcfd, 2,700 BOPD

2012 Key Wells

Approximately 70,000 net acres in

Roberts, Hemphill, and Wheeler Counties

90% of the acreage HPB

Continuous 2 rig drilling program with

plans for additional rigs starting in 2014

Upper Granite Wash, Hogshooter and Cottage Grove Oil and Liquid Rich Gas Plays

Drill stacked laterals from multi-well pads

in Upper Granite Wash Pay of the Buffalo

Wallow Field

3 to 4 wells per pad

Reduce well cost ~ 10%

Expand play to other Granite Wash

Expand Hogshooter / Cottage Grove play to

newly acquired acreage closer to the

mountain front

Samson Rigs

2013 Activity

Overview

Active Rigs

Balanced approach of acreage optimization, cost initiatives and exploration creates a visible runway

Davis 64 (Cottage Grove and Hogshooter) 64-5H IP 24: 7.0 MMcfd + 2,300 BOPD

64-9H IP 24: 2.6 MMcfd + 1,900 BOPD 64-10H IP 24: 2.7 MMcfd + 2,000 BOPD

Asset Map

13

Horizontal Oil Play

Legacy acreage position provides broad

exposure to stacked pay across the

region

Operate 2 rigs through 2013, drilling 8

Marmaton horizontals with ~20

additional locations

Drilled 3 Mississippi Lime wells in 2013

with encouraging results and ~20

unrisked future locations.

Samson Rigs

Active Rigs

Chesapeake Roark Trust 1-14H IP30: 2,765 BOEPD

Samson Maxon 2-13H Currently completing

Apache Skyy 2-33H EUR 209 MBO 5.2 BCF

Apache Galileo 2-4H EUR 128 MBO 3.7 BCF

Apache Screaming Eagle 1-16H EUR 160 MBO 2.3 BCF

2013 Planned Drilling

Overview Asset Map - Marmaton Activity

Continue optimizing HBP acreage by drilling horizontal oil targets – Expand adjacent leasehold to core up position

14

East Texas Operations

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,

75,000 net acres high graded and HBP

providing exposure to improving future gas

markets

Overview Asset Map – E TX / NW LA

Net Acreage: ~450,000

Proved Reserves: 608 Bcfe

Q1’13 Average Daily Production : 195 MMcfe/d

Oil 5%; NGL 10%; Gas 85%

Current Rig Count: 2

Active Rigs as of June 2013

15

East Texas – Cotton Valley Liquids-rich Stacked Lateral Development

Cotton Valley Highlights

Added a second rig in May 2013

Plan to drill ~ 20 CV Horizontal wells in 2013

Primary targets include B and C Sands

Focused on cost efficiencies

Multi-well pads; currently drilling a 7-well pad

Zipper Fracs

Drilling stacked laterals

Bi-fuel rigs capable of using natural gas and diesel

Currently 24 Horizontal CV wells producing

Focus Area - Southeast Carthage Field

Cost control has led redevelopment of legacy asset

Twomey Heirs #3H (Cotton Valley C Completion)

30 Day IP - 7,280 Mcfd & 454 BOPD

Key Wells

Samson Rigs

Werner-Caraway SL #7H (7 Well Pad)

16

Reserve Summary NSAI SEC Reserve Report – 12/31/2012

PDP Reserves – by Product Total Proved Reserves – by Product PUD Reserves – by Product

2,014 Bcfe 34% Liquids

1,308 Bcfe 21% Liquids

706 Bcfe 59% Liquids

Oil

(MMBbl) NGL

(MMBbl) Gas (Bcf)

Total (Bcfe)

PV-10 ($MM) % Liquids

PDP 24 22 1,021 1,297 $1,874 21%

PDNP 0 0 9 11 15 16%

PUD 44 25 293 706 851 59%

Total 68 47 1,323 2,014 $2,740 34%

Oil 20%

NGLs 14% Gas

66%

Oil 11%

NGLs 10%

Gas 79%

Oil 38%

NGLs 21%

Gas 41%

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

17

Financial Strategy

Committed to a Strong and Stable Capitalization Profile

Target long-term leverage of 3.5x or below while maintaining financial flexibility to execute on capital plan objectives

Focus on maintaining solid liquidity position – ~$1.42 billion as of 6/30/13

No near-term maturities – helps mitigate liquidity risk

Capital Spending Decisions Driven by Risked Discounted Cash Flow

Minimum of 20% IRR required for all capital projects

Project level cash flow generation and sale of non-core assets will significantly 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

18

$360 $1,420

$1,000

$2,250

$0 $500 $1,000 $1,500 $2,000 $2,500

2016

2017

2018

2019

2020

Revolver - Borrowings Revolver - Availability Second Lien Senior Notes

Debt Maturities and Current Liquidity

Debt Maturity Profile and Liquidity ($MM)

(1) Revolver borrowings and availability as of 6/30/2013 (excludes outstanding letters of credit)

Sufficient liquidity – No near-term maturities

(1)

As of June 30, 2013, we had $360 million borrowed under our RBL which results in revolver availability of $1.42 billion

RBL Capacity: $1.78B

19

Current Hedge Position As of July 1, 2013

Year MMBtu/d Swap Price

2013 333,000 $3.75

2014 309,000 $4.15

2015 92,000 $4.09

2016 86,000 $4.08

2017 40,000 $3.92

Year Bbls/d Swap Price

2013 17,500 $92.81

2014 16,500 $90.63

2015 3,500 $90.91

Year Bbls/d Swap Price

2013 8,150 $35.76

Gas Swaps Oil Swaps NGL Swaps

2013: July - December

Hedged ~83% of forecasted July – December 2013 total hydrocarbon volumes

20

Adjusted EBITDA Reconciliation Three Months Three Months Twelve Months

Ended Ended Ended March 31, 2013 March 31, 2012 March 31, 2013

Net income/(loss) $ (58,229) $ (76,968) $ (1,511,290)

Interest expense, net - - -

Provision for income taxes (32,385) (42,177) (796,126)

Depreciation, depletion and amortization (a) 129,063 155,452 656,232

EBITDA $ 38,449 $ 36,307 $ (1,651,184)

Adjustment for unrealized hedging losses 64,020 5,100 64,624

Adjustment for non-cash stock compensation expense (b) 4,961 - 40,567

Adjustment for fees paid to co-investors (c) 5,250 5,000 20,250

Adjustment for fees paid for SOX compliance 194 - 758

Adjustment for restructuring expenses (d) - - 46,643

Adjustment for bad debt expense - - 62

Adjustment for loss on early extinguishment of debt - 44,815 -

Provision to reduce carrying value of oil and gas properties 69,269 91,410 2,231,386

Adjusted EBITDA $ 182,143 $ 182,632 $ 753,106

(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) Management fee paid quarterly (d) Total expenses incurred in Q4 related to the restructuring (including the RIF)

21

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.

Forward Looking Statements

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.