Investor Presentation December 2013

PDNP 1%

PDP 64%

PUD 35%

As of 12/31/12

Focusing on Liquids-rich Targets in Existing Resource Base Company Snapshot

Proved Reserves (12/31/12): 2.0 Tcfe

Q3 2013 Production(1): 582 MMcfe/d

(30% Liquids)

Operated Rigs: 11

Total Net Acres: ~2.2 million

Company Overview

Rockies Targets: Shannon, Sussex, Frontier, Three Forks, Middle Bakken, Ft. Union, Muddy Legacy Position: San Juan

Mid-Continent & East Texas Targets: Marmaton, Granite Wash, Hogshooter / Cottage Grove Wash and Cotton Valley Sands Legacy Position: Haynesville / Bossier

Samson Rigs Samson Office (HQ: Tulsa, OK)

2

Q3’13 Production by Area(1)

Reserves by Category

(MMcfe/d)

East Texas 163

Mid-Con 200

Rockies 219

(1) Includes 11 MMcfe/d of production divested in Q3’13

Committed Leadership with Investor Support

Industry Experience Public Company

Experience

Randy Limbacher - Chief Executive Officer and Director 32+ 32+

Richard Fraley - Executive Vice President and Chief Operating Officer

30+ 25

Phil Cook - Executive Vice President and Chief Financial Officer 25+ 17

Louis Jones - Executive Vice President of Business Development, New Ventures and Portfolio Management

30+ 30+

Andrew Kidd - Senior Vice President and General Counsel 20+ 10

Committed Equity Investors with Significant Industry Experience / Investment Exposure

3

Corporate Strategy

Maximize dollars at the drill bit

Focus on prospects with higher liquids content to improve returns

Reduce costs and improve efficiencies in the field

Delineate the liquids-rich Ft. Union and Granite Wash positions

Bolt-on to existing core positions

Actively monitor M&A market for potential acquisitions that provide visibility and

inventory

Lower exploration risk

Well hedged for the next 18 – 24 months

Non-core assets sales – Divested over $300 million for 2013 YTD

Equity contribution to fund growth from acquisitions or acceleration of delineated

inventory

Position portfolio for public market access

Optimize Capital Program

Future Drill Bit Inventory

Protect the Balance Sheet in Short Term

Long Term Opportunities to

Strengthen Balance Sheet

4

Maximizing Dollars to the Drill Bit

LG&G $17 Facilities

$39

D&C $487

East Texas (14%)

Mid-Continent

(35%)

Rocky Mountains

(51%)

$543 Million

D&C Capital by Division (%)

Capital by Type ($MM)

Capital Spend – Year over Year Comparison

($MM)

Took active steps in early 2013 to reduce

LG&G spending

90% of capital to the drill bit in 2013 versus

76% in 2012

Focused capital dollars on liquids weighted

projects

2013 Strategy

$547 $487

$173

$56

$720

$543

$0

$200

$400

$600

$800

9ME 2012 9ME 2013

D&C LG&G & Other

(9ME 2013)

(9ME 2013)

5

90%

76%

607 605 604 572 568 574 571

0

100

200

300

400

500

600

700

Q1'12 Q2'12 Q3'12 Q4'12 Q1'13 Q2'13 Q3'13

MM

cfe

/d

Divested

Maintaining Base Production

6 (1) Production normalized for divestitures since January 2012

(1)

Delivering Liquids Growth Liquids Production by Quarter(1)

(1) Excludes production associated with all divestitures in 2012 and 2013 to date

9 11 11 11

13 14

9

11 12

13

15 15

19%

21%

23%

26%

29% 30%

0%

5%

10%

15%

20%

25%

30%

35%

0

5

10

15

20

25

30

35

Q1'12 Q2'12 Q3'12 Q1'13 Q2'13 Q3'13

NGL (MBbl/d) Oil (MBbl/d) %liquids

(MBbl/d) (% Liquids)

7

$6.6

$6.0

$6.1

$5.5

$5.0

$5.5

$6.0

$6.5

$7.0

Bakken - Ambrose Field Cotton Valley - SE Carthage

D&

C C

ost

s p

er W

ell (

$M

M)

8

Reducing Drilling & Completion Costs

Down ~8%

Down ~8%

8

Driving Down Costs Across the Portfolio

Pad Drilling Completion – Service Provider Reductions

2012 2013 YTD 2012 2013 YTD

Note: 2013 YTD represents wells completed through August for Bakken and September for Cotton Valley

$94

$84

$0

$25

$50

$75

$100

9ME 2012 9ME 2013

($ MM)

Cash G&A

Improving Relative Cost Structure Commitment to Continual Improvement

9

Lease Operating Expense – Down despite shift to higher cost liquids focused drilling

Cash G&A(1) – Reduced compensation expense

(1) Income Statement G&A excluding non-cash compensation

(1)

$0.93

$0.91

$0.90

$0.91

$0.92

$0.93

$0.94

9ME 2012 9ME 2013

($ per Mcfe)

Lease Operating Expense

Asset Sales – Balance Sheet Protection

$680

~$300

$200+

$0

$200

$400

$600

$800

2012 2013 (E) 2014 (E)

$M

M

Asset Sales

10

Asset Overview

11

Rocky Mountain Operations

Samson Rigs

12

North Dakota

Wyoming

Colorado

Diversified Position Across Several Basins with Catalysts for Growth

Utah

Idaho

Stacked oil plays targeting: Shannon,

Sussex, Muddy, and Frontier Q3’13 Production: 3.6 MBoe/d Rig Count: 2

Powder River Basin:

Three Forks and Middle Bakken

development Q3’13 Production: 4.2 MBoe/d Rig Count: 1

Williston Basin:

Horizontal program in the Ft. Union Q3’13 Production: 77 MMcfe/d Rig Count: 2

Green River Basin:

Mature dry gas asset Q3’13 Production: 95 MMcfe/d

San Juan Basin:

Net Acreage: ~1,000,000

YE 2012 Proved Reserves: 779 Bcfe

Q3’13 Average Daily Production(1): 219 MMcfe/d

Oil 23%; NGL 13%; Gas 64%

Current Rig Count: 5

Rocky Mountains Snapshot:

(1) Includes 11 MMcfe/d of production divested in Q3’13

Significant Resource Potential – Delineation Continues, Sets Stage for Development Drilling in 2014

Green River Basin – Ft. Union Overview Asset Map

13

Upper, Middle, and Lower Prospective Middle and Lower Prospective

HZ Producing Well

Vertical Well (3 Zone Completion)

2013-2014 Lower Target

2013-2014 Middle Target

2013-2014 Upper Target

Polar Bar Recompletion

Rig Count: Currently operating 2 rigs

Acreage: 39,900 Gross / 32,000 Net

Q3’13 Production: 43 MMcfe/d

Operations Update:

First four HZ wells exceeding initial expectations

Polar Bar recompletion results are encouraging

2013-2014 Drilling Season:

Drill & Complete 6 HZ wells

Test spacing & delineate to the Northeast

Test stacked lateral concept

Potential to add rig in 2014

Gross Unrisked Resource Potential

Barricade 41-6 MH EUR: ~11.5 Bcfe Barricade 41-6 LH EUR: ~9 Bcfe

Horizons Spacing # Locations Gross Tcfe6

Lower/Middle/Upper 1,800' 173 1.5

Lower/Middle/Upper 900' 346 3.0

Mid-Continent / East Texas Operations

Legacy Position with Embedded Upside and Strong Natural Gas Option

Samson Rigs

Liquids rich development targeting the

Granite Wash and Marmaton plays Q3’13 Production: 177 MMcfe/d Rig Count: 4

Anadarko Basin:

Oklahoma Cotton Valley Sands Gas Option: Haynesville/Bossier Q3’13 Production: 163 MMcfe/d Rig Count: 2

East Texas / North Louisiana:

Mature Dry Gas Asset Q3’13 Production: 23 MMcfe/d

Arkoma Basin:

Net Acreage: ~954,000

YE 2012 Proved Reserves: 1,235 Bcfe

Q3’13 Average Daily Production: 363 MMcfe/d

Oil 11%; NGL 16%; Gas 73%

Current Rig Count: 6

MC/ET Snapshot:

Texas Louisiana

14

Anadarko Shelf – Granite Wash Overview Granite Wash Asset Map

Rig Count: Currently operating 2 rigs drilling

multi-well pads targeting Granite Wash stacked

pay

Acreage: ~63,000 net acres across Hemphill,

Wheeler and Roberts Counties

~200 potential stacked operated drilling

locations

Next Steps:

2013 Plan: Test three pads with 2 - 4

stacked laterals each

Reduce Well Costs: Average single well

D&C $7.2 MM, currently targeting $6.5

MM via pad drilling

Transition to Pad Drilling Creates Potential for Long-Term Visibility

Samson Rigs

Stacked GW Potential

Pounds 2 Well Pad

Lister 3 Well Pad

Hefley 4 Well Pad

Potential Pad Drilling Locations

Texa

s

Okl

ah

om

a

15

Non Operated Acreage

Operated Acreage

Waiting on completion

Financial Position

Balance Sheet

Committed to improving leverage

Maintain liquidity position

Simple capital structure with no near term maturities

Access equity capital to delever with a growth focused acquisition or acceleration of organic development

Bank Credit Facility

Diversified bank group – 24 banks with no bank over 10%

Borrowing base of $1.78 billion (reaffirmed November 2013)

Hedge Position

Maintain a solid hedge position to protect capital program by reducing price risk

Over 70% hedged on a total hydrocarbons basis for 2014

Initial positions established for 2015

16

Constructing key processes & business systems

Focusing on costs, capital discipline & asset sales

resulting in improved debt metrics & returns

Active in M&A deal flow as we seek to optimize

the portfolio & provide opportunities to de-

leverage the company

Significant potential to add value

Long term natural gas option in East Texas

and Mid-Continent

Ft. Union has upside potential to more

than double current proven reserves

Testing multi-year drilling potential in

Granite Wash

Exploration upside from large land

position

Summary

17

Focusing on Key Building Blocks for the Future

All statements included in this presentation, other than statements of historical fact, may constitute forward-looking statements, including, but not limited to, statements or information regarding our future growth, results of operations, reserves, operational and financial performance, business prospects and opportunities and other 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 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. 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 and assumptions, 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 currently believe to be reasonable, actual results may differ materially from expected results. Factors that may cause actual results to differ from expected results include, but are not limited to: (i) fluctuations in oil and natural gas prices; (ii) the uncertainty inherent in estimating our reserves, future net revenues and PV-10; (iii) the timing and amount of future production of oil and natural gas; (iv) cash flow and changes in the availability and cost of capital; (v) environmental, drilling and other operating risks, including liability claims as a result of our oil and natural gas operations; (vi) proved and unproved drilling locations and future drilling plans; (vii) the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; and (viii) any of the risk factors and other cautionary statements described in our Registration Statement on Form S-4, filed with the Securities and Exchange Commission (the “SEC”) on February 14, 2013, and any other registration statements, reports or other information that we may subsequently file from time to time with the SEC. Readers are cautioned not to place undue reliance on forward-looking statements. Should one or more of the risks or uncertainties referred to 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. Further, new factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible to predict all such factors, or to the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. 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. Each forward-looking statement speaks only as of the date of this presentation, and we undertake no obligation to update or revise any forward-looking statements to reflect subsequent events or circumstances.

Forward-Looking Statements

Appendix

Powder River Basin – North Tree Field Overview Development Map

20

2011-2012 Established Repeatability; 2013 Initiated Development

Rig Count: Currently operating 2 rigs drilling multi-well pads targeting the Shannon formation in North Tree Field

Acreage: ~17,000 net acres

North Tree Activity:

Drilled and completed 7 horizontal wells to test and delineate North Tree Field

7 well average Max IP of 1,440 BOPD and average IP30 of 429 BOPD (range 184-807 BOPD)

Development Plan:

2H 2013: 12 HZ wells from 4 pads using a combination of short and long reach laterals

2014: 16 HZ wells from 8 pads using a combination of short and long reach laterals

Full Scale Potential North Tree Field – 28 additional locations on 320 acre spacing

Carolina (4 Well Pad)

Missouri (4 Well Pad)

Mid-Continent Operations

Legacy Position Continues to Yield New Opportunities

Samson Rigs

Net Acreage: ~574,000

YE 2012 Proved Reserves: 627 Bcfe

Q3’13 Average Daily Production: 200 MMcfe/d

Oil 17%; NGL 21%; Gas 62%

Current Rig Count: 4

Mid-Continent Snapshot:

21

Marmaton Overview Asset Map – Black Kettle

Opportunistic Program with the Potential to Add Scale

22

ROGER MILLS

Samson Rigs

Key Wells

Maxon 2-13H IP 30: 1,300 BOPD;

6.4 MMCFD wet gas

Rig Count: Currently operating 2 rigs in Black

Kettle

Activity Summary:

Six operated wells currently producing

with strong results; liquids cut higher

than expected in current focus area

Continue 2 rig program into 2014

Key Goals and Next Steps:

Reduce drill days / cost

Test down dip and infill spacing -

Success could yield an additional 30+

locations

Leon 3-10H IP 30: 1,200 BOPD;

4.4 MMCFD wet gas Lea Erma 2-15H IP 30: 800 BOPD;

3.0 MMCFD wet gas

Net Acreage: ~380,000

YE 2012 Proved Reserves: 608 Bcfe

Q3’13 Average Daily Production: 163 MMcfe/d

Oil 3%; NGL 10%; Gas 87%

Current Rig Count: 2

East Texas Snapshot:

Liquids Rich and Dry Gas Producing Properties

East Texas Operations

Samson Rigs

23

East Texas – Cotton Valley Cotton Valley Overview Focus Area - Southeast Carthage Field

Transition to Pad Drilling and Focus on Liquids-Rich Intervals has Led to Solid Returns

B Sand Target

Samson Rigs

Werner-Caraway (7 Well Pad)

24

C Sand Target

Rig Count: Operating 2 rigs in SE Carthage Field

Cotton Valley Snapshot:

Acreage: ~31,000 net acres

Primary Targets: CV C & B Sands

Secondary Target: CV Taylor

Q3’13 Production: 71 MMcfe/d

Operating Update:

Continue focusing on SE Carthage liquids rich intervals; 29 locations remaining (as of 10/1)

D&C costs improving, down 8% since 2012

Complete three more wells by year end; 7 well Werner-Caraway pad sales expected Q1’14

Modeled Well Profile – CV C & B Sands:

Working Interest: ~66%

D&C: ~$5.5 MM

3-Stream EUR: 5.1 – 7.4 Bcfe

Reeves 4 Well Pad Avg IP30 – 4.0 MMCFD &

80 BOPD

Biggs (3 Well Pad)

$284 $1,496

$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

Financial Position

(1) Revolver borrowings and availability excludes outstanding letters of credit

Sufficient Liquidity – No Near-term Maturities

(1)

RBL Capacity: $1.78B

Debt Maturity Profile and Liquidity ($MM)

As of October 31, 2013, we had borrowings of ~$284 million on our revolver

25

Current Hedge Position As of November 15 , 2013

Year MMBtu/d(1) Swap Price

2013 330,000 $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(1) Swap Price

2013 17,750 $92.82

2014 16,500 $90.63

2015 3,500 $90.91

Year Bbls/d(1) Swap Price

2013 8,650 $35.81

2014 6,000 $34.94

Gas Swaps Oil Swaps NGL Swaps

2013: Balance of year (1): Volumes are rounded

Hedging Strategy Focused on Protecting Cash Flow From Expected Future Production

26

Adjusted EBITDA Reconciliation Three Months Nine Months Twelve Months

Ended Ended Ended

September 30, 2013 September 30, 2013 September 30, 2013

Net income (loss) $ 6,657 $ 31,472 $ (1,096,163)

Interest expense, net - - -

Provision (benefit) for income taxes 4,110 17,757 (567,653)

Depreciation, depletion and amortization (a) 129,438 386,468 571,991

EBITDA $ 140,205 $ 435,697 $ (1,091,825)

Adjustment for unrealized hedging losses (gains) 32,304 14,367 (32,331)

Adjustment for non-cash stock compensation expense (b) 8,780 19,864 36,494

Adjustment for fees paid to co-investors (c) 5,250 15,750 20,750

Adjustment for fees paid for public company compliance 427 2,704 2,917

(Gain) loss on sale of other property and equipment (2,796) 209 209

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

Adjustment for bad debt expense - - 62

Provision to reduce carrying value of oil and gas properties - 80,330 1,772,870

Unusual or non-recurring charges described in credit agreement 8,585 17,161 17,161

Adjusted EBITDA $ 192,755 $ 586,082 $ 772,950

(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)

27