Samson Resources Corp - FORM 8-K - EX-99.2 - August 17, 2015

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Supplemental Materials
August 2015
Exhibit 99.2

Forward-Looking & Other Cautionary Statements
2
Samson Resources Corporation (“Samson” or the “Company”) is making this previously undisclosed information available to its security holders in connection
with Samson’s previously disclosed evaluations of strategic alternatives with its existing creditors.  This information is not an offer or the solicitation of an offer for any
transaction and may not be used or relied on in connection with any transaction.
Cautionary Statement Regarding Forward-Looking Statements
The information in this presentation by Samson Resources Corporation (the “Company,” “we” or “our”) includes “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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, 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,” “potential,” “goal,” “foresee” 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.
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. Factors that may cause actual results to differ from expected results include, but are not
limited to: (i) our substantial indebtedness; (ii) our ability to refinance, restructure or amend our indebtedness or otherwise improve our capital structure and liquidity; 
(iii) fluctuations in oil and natural gas prices; (iv) the uncertainty inherent in estimating our reserves, future net revenues and PV-10; (v) the timing and amount of future
production of oil and natural gas; (vi) cash flow and changes in the availability and cost of capital; (vii) environmental, drilling and other operating risks, including liability
claims as a result of our oil and natural gas operations; (viii) proved and unproved drilling locations and future drilling plans; (ix) the effects of existing and future laws and
governmental regulations, including environmental, hydraulic fracturing and climate change regulation; (x) restrictions contained in our debt agreements; (xi) our ability to
generate sufficient cash to service our indebtedness; (xii) our ability to make acquisitions and divestitures on favorable terms or at all; and (xiii) any of the risk factors and
other cautionary statements, including under the heading “Risk Factors,” described in the Company’s Annual Report on form 10-K for the year ended December 31, 2014,
and in the other documents and reports we file from time to time with the Securities and Exchange Commission.
Readers are cautioned not to place undue reliance on forward-looking statements. Should one or more of the risks or uncertainties referenced above 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 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.
Each forward-looking statement speaks only as of the date of this presentation, and, 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.
The attached is a compilation of three sets of materials which were presented to (a) certain holders of under the Second Lien Term Loan Credit Agreement and (b) a group of
holders of Senior Notes due 2020 under the Senior Notes Indenture in June, July, and August of 2015.
Non-GAAP Disclosures
This presentation refers to certain non-GAAP financial measures. Definitions of these measures and reconciliation between U.S. GAAP and non-GAAP financial measures are
included at the end of this presentation.

Table of Contents
Business Plan Key Elements
Asset Review
Business Plan and Long-Term Financial Forecast
A&D Considerations
Appendix
3

Information on the Following Pages is as of
June 2015
4

Business Plan Key Elements
5

Key Elements of Business Plan
6
Restructure balance sheet
Complete divestiture program
Restart capital program in early 2016
East Texas and Bakken provide platform
•
Bolt-on acquisitions in East Texas and Bakken
•
Take advantage of Gas Option (Haynesville) when prices improve
Methodically test upside from Fort Union, Granite Wash, and Mowry
Add large resource play acquisition

Asset Review
7

Company Overview
2014 Production: 170 MMcfe/d
Proved Reserves
(1)
:  410 Bcfe
Net Acreage
(2)
: 465,000
Gross Wells: 1,600
West Division
2014 Production: 323 MMcfe/d
Proved Reserves
(1)
:  920 Bcfe
Net Acreage
(2)
: 710,000
Gross Wells: 6,900
East Division
Samson Corporate Offices (HQ: Tulsa, OK)
Total Co. 2014 Production
(3)
:  493 MMcfe/d    /    Proved Reserves
:  1.26 Tcfe
with PV-10 of $1.26 Bn
(4)
(1)
Proved Reserves as of 12/31/2014 pro forma for divestitures through Arkoma sale.
(2)
Net Acreage as of 12/31/2014 in shaded states pro forma for divestitures through Arkoma sale.
(3)
2014 production pro forma for divestures through Arkoma sale.
(4)
NSAI 12/31/2014  reserve report at 3/13/15 strip pricing and pro forma for Arkoma sale.
8
(1)

Asset Overview
Core
Assets
Upside Assets
Non-Core
East Texas
Williston
Granite Wash /
Mississippian
Lime
(3)
Fort Union
Powder River
Basin / Mowry
(4)
Mid-Con Sales
Package, Gas,
Permian
Proved Reserves
(1)
499 Bcfe
12.2 MMboe
239 Bcfe
62 Bcfe
8.2
MMboe
406 Bcfe
Pre-tax
PV-10
(1)
$428 MM
$90 MM
$219 MM
$59 MM
$100 MM
$362 MM
% PDP
(2)
81%
52%
79%
70%
93%
95%
2014 Production
161 MMCFE/d
4.2 MBOE/d
100 MMCFE/d
31 MMCFE/d
4.5 MBOE/d
149 MMCFE/d
Acreage
298,000
98,000
126,500
30,700
292,000
328,000
Well Count
1,670 Operated/
1,030 NonOp
115 Operated/ 120
NonOp
700 Operated/
1,000 NonOp
35 Operated/ 18
NonOp
150 Operated/ 345
NonOp
1,040 Operated/
2,280 NonOp
Advantages
Taylor and
Cotton Valley
economic to
drill at
$3.00/Mcf
gas
Opportunity for
bolt on acreage
to increase
inventory
Predictable well
results
Changes in
development
strategy have
yielded
improved well
results
Active area for
operating
partners
Continuation of
Miss Lime
program to be
determined
during 2015
Liquids-rich gas
play with high
impact
potential
Samson is the
primary
operator in the
play
Mowry
has
potential to be
a resource play
Potentially large
drilling
inventory
Existing
production can
be monetized
Natural buyers
include royalty
MLPs, non-op
companies and
private equity
Disadvantages
Heavy natural
gas exposure
Haynesville
requires $4.00+
gas
Outside of the
basin’s “sweet
spot” with
significant Tier
2 acreage
Repeatability
needs to be
demonstrated
Constrained
drilling season
Repeatability
needs to be
proven
Economic
feasibility not
yet
demonstrated
Scattered and
undeveloped
acreage and
minerals
High non-op
interest
________________________________________________
(1)
NSAI 12/31/2014 reserve report shown at 3/13/15 strip pricing and pro forma for Arkoma sale.
(2)
Percentage of reserves.
(3)
Also includes Marmaton and other stacked production.
(4)
Future focus on Mowry; current production principally located in Frontier and Shannon/Sussex plays.
9

Primary Areas of Operation
Core Assets
Upside Assets
Non-Core Assets
Based upon the strategic review, the geographic profile of the assets is summarized below
Asset Characterization
10
Core Assets
Predictability / institutional knowledge
Contiguous acreage with opportunity for scale
efficiency
Access to midstream assets / distribution
Attractive IRRs at a modest increase to strip
pricing
Upside Assets (Further Testing Required)
Predictability needs to be proven
Reasonable resource potential as techniques
are perfected and consistent cost and reserves
are achieved
Breakeven price still to be determined
Non-Core Assets
Geographically dispersed
Limited drilling inventory combined with low
working interests
Minimal PUD Reserves
Generally well received in A&D market
Difficult to aggregate positions

Pre-tax PV-10 Overview
Samson’s existing proved reserves at current strip have a pre-tax PV-10 of approximately $1.4 billion (including
hedges). At the Business Plan price deck the pre-tax PV-10 increases to $1.7 billion.
________________________________________________
Non-Core Assets:
•
Mid-Con Sales Package
•
Wamsutter / San Juan
•
Permian Minerals
Upside Assets:
•
Granite Wash /
Mississippian Lime
•
Fort Union
•
Powder River Basin /
Mowry
Core Assets:
•
East Texas (incl.
Haynesville)
•
Williston
Pre-tax PV-10
$ in millions
11
$518
$666
$378
$473
$362
$450
$168
$109
$1,426
$1,697
–
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
3/13/15 Strip
Business Plan Price Deck
Core Assets
Upside Assets
Non-Core Assets
Hedges
Source: Company 12/31/14 reserve report run at each respective price deck and is pro forma for Arkoma sale.
Note: Business Plan price deck assumes $3.50/Mcf gas and $65.00/bbl oil by year-end 2015, increasing to $3.75/$67.50 and $4.00/$70.00 in 2016 and 2017, respectively.

Significant Concentration of PV10
12
75% of reserve value is concentrated in less than
1,000 wells
~50% of top quartile are East Texas wells
The lowest value quartile is comprised of ~8,000
wells with an average PV10 of $75,000/well however
5,000 of those wells have less than $10,000/well
remaining in PV10 at recent SEC prices
Average interest in bottom tier of assets is 30%
Non-Core Assets
(1)
account for ~3,320 wells
(1)
Non-Core Defined as Mid-Con Sales Package, San Juan & Wamsutter
(2)
SEC Pricing.
Reserve Analysis
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
25%
50%
75%
100%
% of Reserves Present Value
75% of PV10
Concentrated in <1000 Wells
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
$7,000
$8,000
25%
50%
75%
100%
% of Reserves Present Value

Improving Margins
Cost reduction initiatives have resulted in
approximately $80 MM of annualized savings
375 total headcount reduction
Impacted positions include
management, technical, back office
& field operations
Closed small offices in The Woodlands &
Oklahoma City
Reduced ~100 vehicles from fleet
Consolidation of technical software applications
Shut in ~ 1,000 negative cash flow wells
~30% of gross operated well count
Less than 2% of 1  
quarter net production
Cost Reduction Efforts
Savings Calculations exclude one time costs associated with debt restructuring  and other one time costs such as severance payments.
$29 -
$34
$45-$50
$74 -$84
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
Annualized Improved Margins
LOE
G&A
Total
$0.17 -
$0.20
$0.27 -
$0.30
$0.44 -
$0.50
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
$0.30
$0.35
$0.40
$0.45
$0.50
$/MCFE Improved Margins
LOE
G&A
Total $/MCFE
13
st

Core Assets
14

Asset delivers growth opportunity at consistent returns
Optimizing legacy leasehold position through horizontal
development of the Cotton Valley sands
Industry leader in East Texas Cotton Valley sand development
Exposure to significant resource in Haynesville at improved
prices
Ability to add to position through acquisitions and leasing
(1)
Assumes 3/13/15 strip.
Overview
Overview
Key Statistics
Key Statistics
Acreage Position
Acreage Position
Historical Production
Historical Production
East Texas: Summary
2014 Production: 161 MMcfe/d (15% Liquids)
Net Acreage: 298,000
PV-10 Value: $428 Million
(1)
Taylor
Upper CV
Haynesville
Two
Three
Stacked
Formations
15

Subsurface model developed to maximize
performance
Maximizing recovery through optimized lateral
placement
Well spacing based upon resource in place
Identified liquids rich condensate fairways
Improved drilling and completion techniques allowing
for extended lateral lengths
Exploiting vertical fields with horizontal infill program
Leveraging existing infrastructure to lower facilities
costs and reduce cycle times
C Target
(Lower
Stack)
B Target
(Upper Stack)
New Target
Strategic Highlights
Strategic Highlights
Cotton Valley: Overview
Driving Program Capital Efficiencies
Driving Program Capital Efficiencies
16
SE Carthage Field
CNVL  Stacked C2-B2 Targets
CNVL C1 Sand Target
Top CNVL
1200’ to
base
of C2 Sand
Development Optimization
Development Optimization
Accessing more reservoir by drilling multi-unit laterals
Lateral lengths have increased by an average of 900’
Drilled longest lateral to date (8,550’)
(1)
in January 2015
1Q15 initial production rates averaged over 8
MMCFE/d
Testing increased stimulation designs
Operations Execution
Operations Execution
Target Type
Well
Count
Gross
Avg EUR
Gross Avg
CapEx
Avg Finding
Cost
CV C1 Sand Targets
5
6,937
$6,735
$0.97
CV Stacked B2/C2 Targets
4
4,817
$6,451
$1.34
86%
37%
(1)
2014 record lateral was 7,615’ effective completed length and 8,550’ from Kick off  Point to TD
0
2,000
4,000
6,000
8,000
10,000
2014
2015
$0.00
$0.40
$0.80
$1.20
$1.60
2014
2015

Cycle Time: 10-12 wells/rig/year
Differentials: $0.38/Mcf, $1.55/bbl, 33% NGL
LOE: Fixed $2,437/month + Variable: ($0.26/Mcf, $0.78/bw)
Shrink:
CV
High
-
87%
and
CV
Low
–
98%
Type
Curve
Breakeven
Price
(1)
($/mcf & $/bbl)
P50 EUR
(Bcfe)
P50 D&C
($MM)
Modeled
Locations
Cotton Valley High
$3.05 / $56.5
5.58
$6.03
36
Cotton Valley Low
$5.05
/ $93.78
3.03
$6.35
296
Cotton Valley High
Cotton Valley Low
Well Spacing
1,500 feet
1,500 feet
Avg WI
87.1%
100%
Avg
NRI
66.0%
76.7%
Liquids
25%
21%
Avg
Lateral Length
5,749 ft
4,962 ft
Cotton Valley High curve in line with 2014/15 single target results
Cotton Valley Low curve identifies hydrocarbon in place, but is
reduced for offset depletion
Each location incorporating volumetric recoverable reserves
estimates
Cotton Valley: Inventory
Type Curve Description
Type Curve Description
Average Well Metrics
Average Well Metrics
Type Curves
Type Curves
17
(1)    Breakeven defined as PV15 = 0; with D&C capital reduced by 15%  to $5.1 MM to reflect  vendor savings.

Cycle Time: 10-12 wells/rig/year
Differentials: $0.38/Mcf, $2.65/bbl, 33% NGL
LOE: Fixed $2,027/month + Variable: ($0.12/Mcf, $0.22/bw)
Taylor High
Taylor Med
Taylor Low
Well Spacing
1,500 feet
1,500 feet
1,500 feet
Avg WI
100%
100%
100%
Avg NRI
77.0%
79.5%
75.0%
Liquids
(2)
0%
0%
0%
Avg
Lateral Length
6,655 ft
5,786 ft
5,218 ft
Type
Curve
Breakeven
Price
(1)
($/mcf & $/bbl)
P50 EUR
(Bcfe)
P50 D&C
($MM)
Modeled
Locations
Taylor
High
$2.92 / $54.22
6.05
$6.84
31
Taylor Med
$3.87 / $71.87
4.28
$6.69
93
Taylor Low
$8.21 / $152.47
1.89
$6.33
222
Taylor: Inventory
Type Curve Description
Type Curve Description
Average Well Metrics
Average Well Metrics
Type Curves
Type Curves
Type Curves are truncated & high graded based on EUR
Taylor High represents the top EURs available and would be the first
locations drilled
Each location incorporates volumetric recoverable reserves
estimates
18
(1)     Breakeven defined as PV15 = 0; with D&C capital reduced by 15% to $5.8 MM to reflect vendor savings.
(2)    Taylor produced liquids (condensate and NGL volumes) range from 16- 20% though a majority of wells are unprocessed and settled under keepwhole contractual terms.

Core:
>0.7 BCFE/sec/ft
Tier 1:
0.5 -
0.7 BCFE/sec/ft
Tier 2:
<0.5 BCFE/sec/ft
Increased average lateral lengths from ~4,500’ to ~6,000’
Increased average stimulation from 750 lbs/ft to 1,800 lbs/ft
Increased well density from 4 to 8 wells per section
35% decrease in reported capital since start of horizontal development
200-250% increase in recovery through emerging re-stimulation
Significant inventory exists in Core and Tier 1 acreage
Well performance and cost reductions proven by industry
Inventory economically viable at $4.00/mcfe
40% increase in offsetting well performance since 2010
largely due to evolving completion techniques
Industry drilling wells at $7.5-$8.5MM
Lease position allows for drilling of extended laterals
Acreage positioned in liquids rich area of the play
Bolt on acreage opportunities offsetting Core acreage
Additional potential recovery increase via re-stimulation
Haynesville: Overview
Tier Definitions
Tier Definitions
Samson Inventory Upside
Samson Inventory Upside
Industry Development Enhancements
Industry Development Enhancements
Acreage Position
Acreage Position
19
Rig Activity
LEASEHOLD
APRIL 2015
8 Rigs
JULY 2014
19 Rigs

Cycle Time: 6-8 wells/rig/year
Differentials: $0.60/Mcf, $0.00/bbl, 0% NGL
LOE: Fixed $3,500/month + Variable: ($1.10/bw)
Shrink: 100%
Type
Curve
Breakeven
Price
(1)
($/mcf & $/bbl)
P50 EUR
(Bcfe)
P50 D&C
($MM)
Modeled
Locations
Haynesville
Core
$4.17 / $77.40
4.77
$7.75
334
Haynesville
Tier 1
$5.01 / $93.04
4.47
$8.00
81
Haynesville
Tier 2
$6.03 / $112.00
4.20
$9.00
125
Haynesville Core
Haynesville Tier
1
Haynesville Tier
2
Well Spacing
1,000 feet
1,000 feet
1,000 feet
Avg WI
93.9%
87.0%
75.0%
Avg NRI
74.6%
66.5%
57.7%
Liquids
0%
0%
0%
Avg Lateral
Length
5,840 ft
4,633 ft
6,231 ft
Haynesville Type curves were based on geologic parameters
(thickness, pressure, clay content, and depth) and regional
performance
Type curves based on industry standard completion techniques
(~1500 lbs prop/ft) versus vintage Samson completions
Type Curve Description
Type Curve Description
Average Well Metrics
Average Well Metrics
Type Curves
Type Curves
Haynesville: Inventory
(1)
Breakeven defined as PV15= 0 with P50 Capital & EUR.
20

Added ~44,000 net acres over the past year through targeted acquisitions
and grass roots leasing
Offset competitors identified and reviewed
-
8 Companies with sizeable and attractive positions
-
Greater than 560,000 net acres
-
Greater than 400 MMCFE/d gross operated volumes
Strategic leasing program in place and can initiate with $7.5MM of funding
-
Program will add 25 higher return drilling locations
East Texas Acquisition Strategy
Cotton Valley
Cotton Valley
*Based upon 01/2015 Reported Production
Company
Net Acres
Grs
Op
Prod
(MCFD)*
A
37,500
13,500
B
35,000
60,000
C
72,000
90,000
D
135,000
80,000
E
33,400
19,000
F
28,000
30,000
G
16,000
23,000
H
207,000
95,000
Haynesville
Haynesville
Build upon existing Cotton Valley position leveraging technical staff and
operational presence
Anticipate larger Haynesville players to exit basin in the next several years
-
8
Companies identified
-
Greater than 550,000 net acres + 550,000 gross acres
-
Greater
than
2
BCFE/d
gross
operated
volumes
Opportunities may exist to acquire assets with significant development
locations at attractive valuations
Company
Net Acres
Grs Op
Prod
(MCFD)*
A
85,300
590,000
B
72,000
90,000
C
350,000**
375,000
D
50,000
140,000
E
206,000
420,000
F
190,000**
100,000
G
38,000
120,000
H
107,000
220,000
*Based upon 01/2015 Reported Production
**Gross acreage position
21

Bakken
Overview
Overview
“Cracked the code” with change in completion
methodology, IP’s 50% higher
Predictable well results and costs
Lower quality, higher water cut than core of
basin
Opportunities for bolt on acquisitions exist
Optimizing performance for well spacing
Continuously improve capital well costs
Apply right sized artificial lift throughout well
life cycle
Agricultural surface owners
No federal regulatory seasonal limitations
Severe weather can limit operations
Key Statistics
2014 Production: 4.2 Mboe/d (92% liquids)
Net Acreage: 98,000
Pre-tax PV-10: $90 Million
(1)
Acreage Position
Historical Production
Beetle 3H, Strom 8H,
Ranchero 2H, Coronet 8H 
Avg EUR 467 Mboe
Ranchero 6H, Ranchero 8H
First oil early May
Ness 4H, Ness 6H, Odyssey 6H
Avg EUR 471 Mboe
Stingray 6H,
Charger 8H
Avg EUR 427 Mboe
Dorado 6H, Dorado 8H
Avg
EUR ~400 Mboe
Marauder 1H, Marauder 3H
Avg EUR 438 Mboe
Ambrose Field -
Development
(1)
Assumes 3/13/15 strip.
3.6
4.1
3.9
4.0
3.7
4.0
4.9
3.8
4.7
Q1'13
Q2'13
Q3'13
Q4'13
Q1'14
Q2'14
Q3'14
Q4'14
Q1'15
22

Bakken Technical Evolution
Cumulative production for first 6 months increased 50%
Multiple technical drilling/completion improvements
Changed completion to plug and perf from sliding sleeve
Optimizing well targeting, currently 1,200’ spacing vs 660’
Repeatable results throughout our acreage position
Artificial lift evolution
Utilizing jet pumps for high-rate early production
Shift to lower cost rod pumps as production declines
Bakken Highlights
Operated 2014 Spuds
(2)
Wells on Production
Count of Operated Wells on Production (2014 program)
(1)
0 -
60 days
60 -120
days
120 -180
days
180+ days
Plug
& Perf
11
4
4
0
Sliding
Sleeve
4
4
4
4
0
2
4
6
8
10
12
14
16
$0
$5
$10
$15
$20
$25
$30
$35
$40
Cumulative pre-tax PV-10, $ in millions
Plug & Perf
Sliding Sleeves
________________________________________________
Note: Data set consists of operated analogous wells.
(1)
As of 3/31/15.
(2)
Scorpion plot was run at 2014 SEC price deck.
Cumulative Fluid vs. Producing Days
23

Type Curves
Average Well Metrics
Cycle Time: 18-24 wells/rig/year
Differentials: $2.90/Mcf, $12.00/bbl, 45% NGL
LOE: Fixed $13,760/month + Variable: ($0.10/bo, $1.75/bw)
Shrink: 77%
Type Curve Description
Bakken Inventory
Bakken
type curves all based on Plug & Perf
completion
technique
Bakken
Core –
1,200’ spacing with higher (>40%) oil cut
Bakken
Tier 1 –
1,200’ spacing with lower (<40%) oil cut
within operated production & increased risk factors
Bakken
Tier 2 –
600’ spacing –
infill development program
Bakken Core
Bakken Tier 1
Bakken Tier 2
Well Spacing
1,200 feet
1,200 feet
600 feet
Avg WI
47.2%
52.5%
47.2%
Avg NRI
38.4%
43.0%
38.4%
Liquids
92%
92%
92%
Avg Lateral Length
10,000 ft
10,000 ft
10,000 ft
Type
Curve
Breakeven
Price
(1)
($/mcf & $/bbl)
P50 EUR
(MBOE)
P50 D&C
($MM)
Modeled
Locations
Bakken Core
$3.09/$57.50
430
$6.50
12
Bakken
Tier 1
$3.32/$61.75
405
$6.50
34
Bakken
Tier  2
$3.76/$70.00
345
$6.50
268
(1)
Breakeven defined as PV15 = 0; with D&C capital reduced by 15% to  $5.53 MM to reflect vendor savings.
24

Upside Assets
25

M1
M2
M3
Upper Pay Zone –
1 Target
1 Producing Well
Middle Pay Zone –
3 Targets
10 Producing Wells
Lower Pay Zone –
1 Target
2 Producing Wells
Fort Union Geologic Overview
EUR: ~2.0 BCF
-Uneconomic
EUR: ~7.8 BCF
-Economic.
-Primary target.
EUR: ~2.6 BCF
-Marginally economic
Upper
Middle
Lower
26

Prospect Review -
Mowry
-
Mowry Horizontal Wells
Play Drivers and Risks
Overview
Emerging shale resource play
•
Regional marine shale documented by thousand of wells and
completion tests.
•
Key resource play components comparable to other successful
shale plays.
•
Significantly over-pressured.
•
80+ Mowry
permits in area of interest with 13 horizontal wells
drilled or drilling.
•
Resource potential has been significantly de-risked by wells drilled
by offset operators.
Current Operations
2014 Mowry
pilot well completed and producing
•
Successful hydraulic fracture completion and diagnostic work.
•
Production rate and formation pressure greater than expected.
•
Monitoring rates/pressure to estimate stimulated rock volume and
estimate ultimate recovery from this single stage completion.
Assessing economic viability and magnitude of resource
Tracking ever increasing Industry activity.
Mowry Pilot Well
-
Vertical wells  to other horizons
27
HBP
61%
Undeveloped
26%
Expiring    
<12 Mo
13%
Mowry Leasehold: 76,800 Net acres

•
Statistically significant correlation between
frac
size and well performance.
•
Common attribute of the best resource plays.
•
Statistically significant correlation between
frac
size and well performance.
•
Common attribute of the best resource plays.
Mowry: Production vs Frac Size
28

Significant resource potential held by historical vertical development
•
50,000 net acres with 90 sections operated
Wide range of results to date from horizontal program
•
Well performance ranges from 0.5 Bcfe
to greater than 6 Bcfe
Need to de-risk development through technical work to create viable inventory
•
Currently building sub-surface models.  Unique recoveries predicted for each
location and for each zone
Drilling required to confirm technical models.  Estimate 15-20 wells required
Opportunities exist to improve economics.  Longer laterals and larger stimulations
Granite Wash: Overview
Inventory Assessment Strategy
Inventory Assessment Strategy
Granite Wash Position Detail
Granite Wash Position Detail
29

Upside Assets -
Summary
Mowry
Development
Preliminary analytical models being built to support estimates
Acreage defined by maturity and pressure
Geologic study and recent public production used to assign risk factor
Fort
Union
Development
Play based on 3 targeted horizons (Upper, Middle & Lower Ft Union)
Risking assigned based on PDP offset data and normalized production
Granite Wash
Development
Inventory consists of multiple stacked horizons based on geologic maturity
Spans Atokan, Desmoniesian & Missourian series
Upside Assets
Approximately 2,500 gross un-risked locations
50% operated
Upside of ~2.7 TCFE net
________________________________________________
(1)
3P Inventory will be updated routinely as new information becomes available
30

Business Plan and
Long-Term Financial Forecast
31

Business Plan & Long-Term Forecast Overview
32
The Company has prepared a three year business plan (the “Business Plan”)
In addition to the Business Plan, the Company has also prepared a long-term
forecast (the “Long Term Forecast”) through 2020 in order to help evaluate the
development of upside opportunities
Presented herein are the following scenarios:
•
No Drilling Snapshot
•
Core Asset Development (Bakken / East Texas)
•
Core Asset + Gas Option (Haynesville)

Key Assumptions
33
Key Assumptions
Pricing
Business Plan Price Deck
Base Production
Based on Budget forecast
Non
D&C
Capital Spend
Non-D&C capital expenditures forecasted to be the greater of $40 million / year or
15% of annual D&C capital budget
LOE
Base production lease operating expenses inline with historical per unit metrics,
escalated at 2% per year
New wells brought online 2016+ based on single well cost assumptions
2015
2016
2017
2018
2019
2020
Gas ($/Mcf)
$3.17
$3.75
$4.00
$4.00
$4.00
$4.00
Oil ($/bbl)
$57.88
$67.50
$70.00
$70.00
$70.00
$70.00

Key Assumptions (cont’d)
34
Key Assumptions
G&A
G&A reductions greater than $60 million
(1)
on an annual basis by April 2015 to run
rate of ~$100 million
(2)
, excluding one-time costs
2016 & beyond G&A held constant at the revised G&A run-rate
Working Capital
Working capital assumptions reflect current efforts to manage working capital and
enhance liquidity
Beginning in 2016, working capital assumption return to normalized levels
A&D Activity
Arkoma sold for $48 million in Q1’15
No other assets sales incorporated in the forecast
________________________________________________
(1)
$60 million of savings based on a combination of G&A and LOE savings.  Shown together for modeling purposes.
(2)
Including capitalized G&A.

No Drilling Snapshot
35

No Drilling Snapshot
Daily Production (MMcfe/d)
Adjusted EBITDA ($MM)
Unlevered Free Cash Flow
(2)
($MM)
Capital Incurred
(1)
($MM)
36
(1)
Capital shown does not represent cash capital spent and excludes capitalized G&A (does not account for changes in working capital).
(2)
Calculated as Adjusted EBITDA, plus proceeds from asset divestitures, less capital expenditures and changes in working capital.  Adjusted EBITDA excludes restructuring charges in 2015 and Q1 2016 of
$110 million and $15 million, respectively.

Financial Summary –
No Drilling
________________________________________________
(1)
Represents capital expenditures incurred, inclusive of capitalized G&A.
(2)
Excludes impact of working capital changes due to changes in accrued interest liability account.
37
($ in millions)
FY
FY
FY
FY
FY
FY
2015
2016
2017
2018
2019
2020
PRICING
Oil ($/bbl)
57.88
67.50
70.00
70.00
70.00
70.00
Gas ($/mcf)
3.17
3.75
4.00
4.00
4.00
4.00
NGL ($/bbl)
20.78
23.08
24.00
24.00
24.00
24.00
NET PRODUCTION
Crude Oil (MMBbls)
4.2
2.9
2.3
1.9
1.6
1.5
Natural Gas (Bcf)
116.4
92.8
79.0
69.6
62.3
56.3
NGL (MMBbls)
4.2
3.1
2.5
2.2
1.9
1.7
TOTAL NET PRODUCTION (Bcfe)
166.9
128.7
107.6
94.0
83.6
75.5
Daily Rate (MMcfe/d)
457
352
295
257
229
206
% Liquids
30%
28%
27%
26%
26%
25%
TOTAL NET REVENUE
694
550
466
405
359
323
ADJUSTED EBITDA
368
279
221
178
145
119
Capital
Expenditures
(174.2)
(46.5)
(45.0)
(45.0)
(45.0)
(45.0)
Working
Capital
(105.5)
(18.4)
(1.6)
(3.0)
(4.8)
(2.4)
Asset Sales
44.9
-
-
-
-
-
UNLEVERED FREE CASH FLOW
133.2
214.3
174.7
129.8
94.9
71.9
1
2

Core Asset Development
38

Development Assumptions: Core Business Plan
Key Assumptions
2015 Drilling
No drilling for remainder of 2015
East
Texas
Restart program 1/1/2016
(1)
2016
drilling
program
–
1
operated
rig
targeting
Cotton
Valley
and
1
operated
rig
targeting Taylor wells
2017+
drilling
program
–
rig
counts
held
constant
through
2020
Williston
Restart program 1/1/2016
(1)
2016
drilling
program
–
2
operated
rigs
and
1.5
non-operated
rigs
in
Bakken
2017
drilling
program
–
2
operated
rigs
and
1
non-operated
rig
in
Bakken
2018+
drilling
program
–
rig
counts
held
constant
at
2017
levels
until
locations
depleted
________________________________________________
(1)
Program restart dependent on two key factors: 1) appropriate commodity environment to achieve acceptable project returns and 2) ability to spend preparatory capital in advance of
the 1/1/16 start date, such as building pad locations, ordering long lead items and appropriate title work.
39

Core Asset Business Plan
Capital Incurred
(1)
($MM)
Daily Production (MMcfe/d)
Adjusted EBITDA ($MM)
Unlevered Free Cash Flow
(2)
($MM)
________________________________________________
40
$166
$290
$303
$316
$328
$315
$100
$200
$300
$400
$500
$600
2015
2016
2017
2018
2019
2020
Budget
CV/Taylor
Williston
Non D&C
457
397
416
417
404
389
-
100
200
300
400
500
600
2015
2016
2017
2018
2019
2020
Base
CV/Taylor
Williston
$368
$349
$424
$440
$434
$425
$0
$100
$200
$300
$400
$500
$600
2015
2016
2017
2018
2019
2020
$133
$121
$128
$118
$99
$96
$0
$200
$400
$600
$800
$0
$100
$200
$300
$400
2015
2016
2017
2018
2019
2020
(1)
Capital shown does not represent cash capital spent and excludes capitalized G&A (does not account for changes in working capital).
(2)
Calculated as Adjusted EBITDA, plus proceeds from asset divestitures, less capital expenditures and changes in working capital.  Adjusted EBITDA excludes restructuring charges in 2015 and 
Q1 2016 of $110 million and $15 million, respectively.

Financial Summary –
Core Asset Business Plan
________________________________________________
(1)
Represents capital expenditures incurred, inclusive of capitalized G&A.
(2)
Excludes impact of working capital changes due to changes in accrued interest liability account.
41
($ in millions)
FY
FY
FY
FY
FY
FY
2015
2016
2017
2018
2019
2020
PRICING
Oil ($/bbl)
57.88
67.50
70.00
70.00
70.00
70.00
Gas ($/mcf)
3.17
3.75
4.00
4.00
4.00
4.00
NGL ($/bbl)
20.78
23.08
24.00
24.00
24.00
24.00
NET PRODUCTION
Crude Oil (MMBbls)
4.2
3.6
4.4
4.7
4.9
5.1
Natural Gas (Bcf)
116.4
102.0
102.6
101.1
96.0
90.8
NGL (MMBbls)
4.2
3.6
3.7
3.8
3.7
3.5
TOTAL NET PRODUCTION (Bcfe)
166.9
145.3
151.7
152.1
147.5
142.3
Daily Rate (MMcfe/d)
457
397
416
417
404
389
% Liquids
30%
30%
32%
34%
35%
36%
TOTAL NET REVENUE
694
634
711
725
717
706
ADJUSTED EBITDA
368
349
424
440
434
425
Capital Expenditures
1
(174.2)
(295.2)
(308.1)
(321.3)
(332.8)
(320.0)
Working Capital
2
(105.5)
66.9
11.8
(0.7)
(2.0)
(8.9)
Asset Sales
44.9
-
-
-
-
-
UNLEVERED FREE CASH FLOW
133.2
120.8
127.8
117.6
99.4
95.8

Business Plan with Gas Option
42

Development Assumptions: Gas Option
43
Key Assumptions
Core Assets
Consistent with Core Asset Business Plan presented on previous pages
Haynesville Gas
Option
1 rig running in 2018 and 2 rigs running in 2019 and beyond
Each rig drills 11 wells / rig / year
Learning curve on first 10 wells drilled with 25% higher D&C costs

Core Asset Business Plan + Gas Option Case
Capital Incurred
(1)
($MM)
Daily Production (MMcfe/d)
Adjusted EBITDA ($MM)
Unlevered Free Cash Flow
(2)
($MM)
________________________________________________
44
457
397
416
436
471
499
100
200
300
400
500
600
2015
2016
2017
2018
2019
2020
Base
CV/Taylor
Haynesville
Williston
$166
$290
$303
$424
$509
$499
$100
$200
$300
$400
$500
$600
2015
2016
2017
2018
2019
2020
Budget
CV/Taylor
Haynesville
Williston
Non D&C
$368
$349
$424
$462
$512
$553
$0
$100
$200
$300
$400
$500
$600
2015
2016
2017
2018
2019
2020
$133
$121
$128
$56
$16
$40
$0
$200
$400
$600
$800
$0
$100
$200
$300
$400
2015
2016
2017
2018
2019
2020
(1)
Capital shown does not represent cash capital spent and excludes capitalized G&A (does not account for changes in working capital).
(2)
Calculated as Adjusted EBITDA, plus proceeds from asset divestitures, less capital expenditures and changes in working capital.  Adjusted EBITDA excludes restructuring charges in
2015 and Q1 2016 of $110 million and $15 million, respectively.
-

Financial Summary –
Gas Option Case
________________________________________________
(1)
Represents capital expenditures incurred, inclusive of capitalized G&A.
(2)
Excludes impact of working capital changes due to changes in accrued interest liability account.
45
($ in millions)
FY
FY
FY
FY
FY
FY
2015
2016
2017
2018
2019
2020
PRICING
Oil ($/bbl)
57.88
67.50
70.00
70.00
70.00
70.00
Gas ($/mcf)
3.17
3.75
4.00
4.00
4.00
4.00
NGL ($/bbl)
20.78
23.08
24.00
24.00
24.00
24.00
NET PRODUCTION
Crude Oil (MMBbls)
4.2
3.6
4.4
4.7
4.9
5.1
Natural Gas (Bcf)
116.4
102.0
102.6
108.0
120.5
131.0
NGL (MMBbls)
4.2
3.6
3.7
3.8
3.7
3.5
TOTAL NET PRODUCTION (Bcfe)
166.9
145.3
151.7
159.0
171.9
182.5
Daily Rate (MMcfe/d)
457
397
416
436
471
499
% Liquids
30%
30%
32%
32%
30%
28%
TOTAL NET REVENUE
694
634
711
749
803
847
ADJUSTED EBITDA
368
349
424
462
512
553
Capital Expenditures
1
(174.2)
(295.2)
(308.1)
(428.6)
(513.7)
(504.2)
Working Capital
2
(105.5)
66.9
11.8
22.8
17.0
(9.0)
Asset Sales
44.9
-
-
-
-
-
UNLEVERED FREE CASH FLOW
133.2
120.8
127.8
56.0
15.7
39.6

Upside Asset Testing
46

Upside Assets -
Summary
Mowry
Development
Preliminary analytical models being built to support estimates
Acreage defined by maturity and pressure
Geologic study and recent public production used to assign risk factor
Fort
Union
Development
Play based on 3 targeted horizons (Upper, Middle & Lower Ft Union)
Risking assigned based on PDP offset data and normalized production
Granite Wash
Development
Inventory consists of multiple stacked horizons based on geologic maturity
Spans Atokan, Desmoniesian & Missourian series
Upside Assets
(1)
Approximately 2,500 gross un-risked locations
50% operated
Upside of ~2.7 TCFE net
________________________________________________
(1)
3P Inventory will be updated routinely as new information becomes available
47

Key Assumptions
Mowry
Development
Operated only development, 12 wells / rig / year
Drilling pace: 1 well in 2016, 6 wells in 2017, 1 rig in 2018, 3 rigs in 2019,
5 rigs in 2020
Learning curve:  25% higher costs and 50% of expected EUR on first 20 wells
drilled
Fort
Union
Development
Operated only development, 4 wells / rig / year
Drilling pace: 1 rig 2016, 2 rigs in 2017 & beyond
Learning curve:  50% higher costs and 50% of expected EUR on first 5 wells
drilled
Granite Wash
Development
Operated only development, 12 wells / rig / year
Drilling
pace:
2
rigs
2016
&
beyond
(one
rig
allocated
to
Atokan
Granite
Wash
and one rig allocated to Des Moines Granite Wash)
Learning curve:  20% higher costs and 75% of expected EUR on first 5 wells
drilled (for each target)
Cost to Test
48

A&D Considerations
49

A&D Strategy
Previously marketed assets can be sold at
proper time
San Juan, Wamsutter, Non-Core Mid-Con
Reduce scattered acreage & horizons to
simplify asset base
Leverage minerals & areas with limited
inventory to re-deploy capital into core
areas with upside potential
Focus on Bakken
&
East Texas
Reasonable leasing & acquisition prices in
offsetting leasehold
Utilize in house geologic and technical skills
Clear line on growth possibilities through
both small acquisitions and organic leasing
efforts
Targeting repeatable inventory
High return projects needed
Ability to ramp and sustain mid/high activity
levels
Strengthen portfolio by adding ability to
transact in competitive environments
Desire to consolidate following initial
acquisition
Most interested in basins where institutional
knowledge has already been developed
•
Eagle Ford
•
Permian
•
East Texas
•
Bakken
Divestitures
Large Scale Transformation
Bolt-On
Acquisitions
50

Sell Non-Core Assets
Mid-Con Sale Package
Gas Assets
Permian Minerals
Overview
Acreage is primarily scattered
and non-op
San Juan and Wamsutter
Generally mature producing
assets
Exposure to all major plays in
the Permian basin
100% of current production is
non-op
99% is net fee mineral coverage
Current
Operations
Not an area of focus for
development due to low
working interests over multiple
plays
Continue to evaluate well
proposals from outside
operators
Continue to assess behind pipe
resource and workover
candidates
Few drilling opportunities
remain
Limited optimization
opportunities
Not part of future core area
Acreage is scattered over 50
counties
Interest is predominantly
composed of royalties/overrides
Minimal existing production
Key Statistics
Q4’14 Production: 61 MMcfe/d
(30% Liquids)
Net Acreage: 223,000
Proved Reserves: 179 Bcfe
Q4’14 Production: 87 MMcfe/d
(3% Liquids)
Net Acreage: 43,000
Proved Reserves: 226 Bcfe
Q4’14 Production: <1 MMcfe/d
(75% Liquids)
Net Acreage: 62,000
Proved Reserves: 1.2 Bcfe
51

Appendix
52

Hedge Position
The company is well hedged through 2016 and has significant unrealized value in the hedge book.
________________________________________________
Unrealized Hedge Book
Production % Hedged
(2)
53
(1)
Natural Gas Collars: 2016 - 30,000 MMBtu/d in effect only if counterparty elects to exercise (extendable collars).
(2)
% Hedged based on Business Plan.
Natural Gas Swaps & Collars
(1)
Year
Hedged (MMBtu/d)
Wtd. Avg. Swap Price
2015
191,000
$4.05
2016
161,000
4.04
2017
40,000
3.92
Oil Swaps
Year
Hedged (Bbls/d)
Wtd. Avg. Swap Price
2015
3,500
$90.91
NGL Swaps
Year
Hedged (Bbls/d)
Wtd. Avg. Swap Price
2015
750
$37.07

Reconciliation of Strip Pre-tax PV-10 + Hedges to SEC PV-10
Proved Reserve Value:
Based on unrisked
1P Company Reserve Report with 3/13/15 strip pricing
Reserve report incorporates production taxes, ad valorem taxes, operating expenses, AROs and capital expenditures
Commodity price differentials based on reserve report
Shown incorporating 10% discount rate
Factors in hedges in place as of 12/31/2014, run at 3/13/15 strip pricing
($ in millions)
________________________________________________
Source:  Company final 12/31/2014 reserve report run at 3/13/15 strip. Pro forma for Arkoma sale.
Note:  PV-10 using 12/31/14 SEC pricing displayed above for Proved Asset Values (Unrisked). Proved reserve value and hedges use 10% discount rate. Valuation date of
12/31/2014.
Reconciliation of Pre-tax PV-10 at strip pricing to Pre-tax PV-10 at SEC pricing is illustrated below.
54
$1,258
$1,426
$168
$27
$1,267
$2,551
$500
$1,000
$1,500
$2,000
$2,500
$3,000
–
Proved PV-10 @
Strip + Hedges
Hedge Adjustment
Proved PV-10 @
Strip
Asset Sales
Strip Adjustment
Proved PV-10 @ SEC
Pricing

Final NSAI 12/31/14 Reserve Report Summary
________________________________________________
Note: Reflects 3/13/15 strip pricing.
(1)   Pro forma for the sale of the company’s Arkoma assets (PV-10 of $28 million).
The following reflects a summary of the Company’s 12/31/14 reserve report as audited by NSAI.
($ in 000's)
Granite Wash /
Powder
Mid-Con,
East Texas
Williston
Mississippi Lime
Fort Union
River / Mowry
Gas, Permian
(1)
Total
Proved Developed Producing
Oil (MBbls)
2,147
5,285
3,301
592
6,249
2,661
20,234
NGLs (MBbls)
6,534
397
7,440
2,643
549
6,637
24,200
Natural Gas (MMcf)
352,424
4,151
124,244
24,071
4,688
328,255
837,833
Total (Mmcfe)
404,509
38,238
188,690
43,484
45,476
384,042
1,104,439
PV-10 ($ mm)
$430,509
$81,400
$228,944
$52,901
$104,342
$362,558
$1,260,655
Proved Non-Producing
Oil (MBbls)
0
0
0
97
0
0
97
NGLs (MBbls)
0
0
0
411
0
0
411
Natural Gas (MMcf)
0
0
0
3,028
0
0
3,028
Total (Mmcfe)
0
0
0
6,073
0
0
6,073
PV-10 ($ mm)
–
–
–
$4,933
–
–
$4,933
Proved Undeveloped
Oil (MBbls)
654
5,112
1,054
257
579
499
8,155
NGLs (MBbls)
3,435
333
2,180
840
16
1,183
7,987
Natural Gas (MMcf)
70,262
2,560
31,101
6,164
110
11,976
122,174
Total (Mmcfe)
94,797
35,226
50,504
12,751
3,681
22,066
219,025
PV-10 ($ mm)
($2,949)
$8,707
($9,743)
$1,202
($4,095)
($587)
($7,464)
Total
Oil (MBbls)
2,801
10,396
4,354
946
6,828
3,160
28,486
NGLs (MBbls)
9,969
729
9,620
3,894
565
7,820
32,598
Natural Gas (MMcf)
422,685
6,711
155,345
33,263
4,798
340,231
963,034
Total (Mmcfe)
499,306
73,464
239,193
62,308
49,157
406,108
1,329,536
PV-10 ($ mm)
$427,561
$90,107
$219,201
$59,037
$100,247
$361,971
$1,258,124
PV-10 of Hedges ($ 000's)
$168,098
Total PV-10 ($ 000's)
$1,426,222
55

3/31/15 Reserve Report Summary
________________________________________________
Note: Reflects 6/5/15 strip pricing.
The following reflects a summary of the Company’s internal 3/31/15 reserve report
56
($ in 000's)
Granite Wash /
Powder
Mid-Con,
East Texas
Williston
Mississippian Lime
Fort Union
River / Mowry
Gas, Permian
Total
Proved Developed Producing
Oil (Mbbls)
2,116
6,957
3,690
784
6,308
2,756
22,611
NGLs (Mbbls)
7,064
420
7,313
3,518
612
7,487
26,414
Natural Gas (MMcf)
344,717
4,279
125,311
29,801
5,739
330,305
840,151
Total (MMcfe)
399,796
48,541
191,330
55,609
47,257
391,765
1,134,299
PV-10
$411,110
$127,987
$230,754
$75,035
$118,089
$336,886
$1,299,860
Proved Non-Producing
Oil (Mbbls)
-
-
13
-
-
-
13
NGLs (Mbbls)
-
-
11
-
-
-
11
Natural Gas (MMcf)
-
-
111
-
-
-
111
Total (MMcfe)
-
-
257
-
-
-
257
PV-10
-
-
$719
-
-
-
$719
Proved Undeveloped
Oil (Mbbls)
678
3,512
1,703
200
-
442
6,536
NGLs (Mbbls)
3,615
252
2,811
877
-
811
8,367
Natural Gas (MMcf)
74,479
1,795
36,383
6,444
-
9,167
128,269
Total (MMcfe)
100,241
24,382
63,468
12,905
-
16,687
217,683
PV-10
$15,367
$774
$9,663
$943
-
($7,445)
$19,302
Total
Oil (Mbbls)
2,794
10,469
5,407
984
6,308
3,198
29,160
NGLs (Mbbls)
10,679
672
10,135
4,394
612
8,298
34,791
Natural Gas (MMcf)
419,197
6,073
161,805
36,245
5,739
339,472
968,531
Total (MMcfe)
500,038
72,923
255,055
68,514
47,257
408,452
1,352,239
PV-10
$426,477
$128,760
$241,136
$75,978
$118,089
$329,441
$1,319,882
PV-10 of Hedges ($ 000's)
128,404
Total PV-10 ($ 000's)
$1,448,285

Net Operating Losses and Tax Basis Detail
NOL Schedule
Asset Tax Basis as of 12/31/2014
Current Assets
Accounts Receivable
$ 174
Prepaid Expenses
11
Total
185
             
Property, Plant & Equipment
Lease and well equipment (net of depreciation)
$ 117
Producing leasehold cost (net of depletion)
475
             
Capitalized IDC (net of amortization)
235
             
Proved Undeveloped Leasehold
267
             
G&G (net of amortization)
2
                 
Tax depletion carryover
9
                 
Other PP&E
40
               
Total
$ 1,143
Other
Capitalized loan costs
195
             
Goodwill
6
                 
Inventory in excess of book basis
10
               
Total
$ 211
Total
$ 1,539
Subject to 382 Limitation
SRCorp
SIC
SCEEP
PYR
Total
NOL as of 12/31/13
$ 862
$ 401
$ 55
$ 33
$ 1,350
Estimated NOL Generated 12/31/14
95
               
-
              
-
              
-
              
95
               
Estimated Total NOL 12/31/14
957
             
401
             
55
               
33
               
1,445
         
Yearly Limitation - Section 382
$ 133
$ 3
$ 2
138
             
Tax Year 2014 Analysis
Cumulative Section 382 Unused as of 12/31/14
-
              
401
             
19
               
15
               
435
             
Available for use 12/31/14
$ 957
$ 401
$ 19
$ 15
$ 1,392
57

Information on the Following Page is as of
July 2015
58

Play
Cotton
Valley
Cotton
Valley
Haynesville
Haynesville
Haynesville
Taylor
Taylor
Taylor
Bakken
Bakken
Bakken
Tier
High
Low
Core
Tier 1
Tier 2
High
Medium
Low
Core
Tier 1
Tier 2
Production Assumptions
ARIES EUR (P50)
Gas EUR / Well (Bcf)
5.4
          
2.9
          
4.8
          
4.5
          
4.2
          
5.8
          
4.1
          
1.8
          
0.3
          
0.3
          
0.2
          
Oil EUR / Well (MMBbls)
0.0
          
0.0
          
-
            
-
            
-
            
0.0
          
0.0
          
0.0
          
0.4
          
0.4
          
0.3
          
Total EUR (Bcfe)
5.6
          
3.0
          
4.8
          
4.5
          
4.2
          
6.0
          
4.3
          
1.9
          
2.6
          
2.4
          
2.1
          
NGL EUR / Well (MMBbls)
0.2
          
0.1
          
-
            
-
            
-
            
0.2
          
0.2
          
0.1
          
0.0
          
0.0
          
0.0
          
Water (MMBbls)
1.7
0.9
0.2
0.1
1.6
1.2
1.4
0.2
0.4
0.4
0.3
Lease Operating Expense Assumptions
Fixed Operating Expenses ($ / Well / Month)
$2,437
$2,437
$3,500
$3,500
$3,500
$2,027
$2,027
$2,027
$13,760
$13,760
$13,760
Natural Gas Operating Expenses ($ / Mcf)
0.26
0.26
-
-
-
0.12
0.12
0.12
-
-
-
Crude Oil Operating Expenses ($ / Bbl)
-
-
-
-
-
-
-
-
0.10
0.10
0.10
Water Operating Expenses ($ / Bbl)
0.78
0.78
1.10
1.10
1.10
0.22
0.22
0.22
1.75
1.75
1.75
Production Tax Assumptions
Severance Tax Natural Gas (%)
3.7%
3.7%
3.7%
3.7%
3.7%
3.7%
3.7%
3.7%
5.2%
5.2%
5.2%
Severance Tax Crude Oil (%)
5.2%
5.2%
5.2%
5.2%
5.2%
5.2%
5.2%
5.2%
11.3%
11.3%
11.3%
Severance Tax Crude NGL (%)
3.7%
3.7%
3.7%
3.7%
3.7%
3.7%
3.7%
3.7%
6.9%
6.9%
6.9%
Ad Valorem Tax (%)
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
2.7%
0.0%
0.0%
0.0%
Differential Assumptions
Natural Gas ($ / Mcf)
($0.38)
($0.38)
($0.60)
($0.60)
($0.60)
($0.38)
($0.38)
($0.38)
($2.90)
($2.90)
($2.90)
Crude Oil ($ / Bbl)
($1.55)
($1.55)
$0.00
$0.00
$0.00
($2.65)
($2.65)
($2.65)
($12.00)
($12.00)
($12.00)
NGL Realized Price (% of y-grade)
98.5%
98.5%
98.5%
98.5%
98.5%
98.5%
98.5%
98.5%
139.7%
139.7%
139.7%
NGL Transportation + Fractionation
($5.70)
($5.70)
($5.70)
($5.70)
($5.70)
($5.70)
($5.70)
($5.70)
($21.30)
($21.30)
($21.30)
Shrink Factor Assumptions
Shrink Factor
86.9%
98.0%
100.0%
100.0%
100.0%
84.0%
84.0%
84.0%
77.0%
77.0%
77.0%
Drilling & Completion Costs per Well ($mm) (1)
Drilling
$3.4
$3.8
$4.5
$4.5
$4.8
$4.0
$4.0
$3.8
$3.3
$3.3
$3.3
Completion
2.6
2.5
3.3
          
3.5
          
4.3
          
2.8
2.7
2.5
3.2
3.2
3.2
Total
$6.0
$6.3
$7.8
$8.0
$9.0
$6.8
$6.7
$6.3
$6.5
$6.5
$6.5
Location Assumptions
Gross Operated Wells
36
296
334
81
125
31
93
222
12
34
268
Working Interest (%)
87.1%
100.0%
93.9%
87.0%
75.0%
100.0%
100.0%
100.0%
47.2%
52.5%
47.2%
Net Revenue Interest (%)
66.0%
76.7%
74.6%
66.5%
57.7%
77.0%
79.5%
75.0%
38.4%
43.0%
38.4%
Drill Wedge Inputs & Assumptions
59
________________________________________________
(1)
D&C costs shown before 15% savings

Information on the Following Pages is as of
August 2015
60

(1)
As of 2Q Close
Marginal Well Update
Company has prioritized shut-in’s of wells which exhibit lifting costs in excess of current commodity prices
75% of Proven PV10 is concentrated in less than 800 wells
(1)
Since Jan 2014, Samson has divested of 2,900 wells (580 Operated)
Ongoing review for small divestiture packages
Non-Operated wells are also under review in lower commodities
~ 1,000 wells –
~30% of gross operated inventory shut-in between April and May 2015
Aggregate net production of ~6 MMcfe/d in 2
Quarter
Continue to produce marginal wells if:
Negative Op income is largely due to onetime repair
If lease operating efficiency is being improved
Producing in paying quantities and holding lease
Hedges in place may also influence shut-in strategy
State regulations vary in timing but no expectation that P&A program increases significantly in near future
Following the shut in initiative, 80-90% of operated wells exhibit positive cash flow at current pricing
61
nd

________________________________________________
Note:  PV10 data shown Pre-Tax, Pre-G&A.  Excludes items such as Non-D&C capital, midstream income and other corporate items.
Core 6/30/15 PV10 at Various Prices
62
1,131
1,357
1,418
28
88
100
7
26
$1,159
$1,452
$1,544
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
$3/$55/$19.25 Flat
$3/$55/$19.25 Through 2016,
$3.50/$60/$21 Thereafter
$3/$55/$19.25 Through 2016,
$3.50/$65/$22.75 Thereafter
BASE
CV / Taylor
Williston

Compensation Breakout
($ in MM)
(1)
Represents employees and related compensation as of August 3, 2015.
(2)
Benefits assumed to be 35% of employee wages.
63
Employee
1
Compensation
1
Function
Count
Wages
Bonus
Benefits
2
Total
Petrotechnical Staff / Support
382
41.8
$            
11.5
$          
14.6
$          
67.8
$          
Accounting / Finance
107
9.0
1.8
3.1
13.9
Information Systems
46
4.9
1.1
1.7
7.7
Regulatory
37
4.6
1.2
1.6
7.4
Executive
4
2.3
2.3
0.8
5.5
Corporate Other
27
2.8
0.8
1.0
4.5
Other
3
0.4
0.0
0.1
0.5
Total
606
65.7
$            
18.8
$          
23.0
$          
107.5
$        
Employee
1
Compensation
1
Location
Count
Wages
Bonus
Benefits
2
Total
Tulsa, OK
343
39.3
$            
12.2
$          
13.7
$          
65.2
$          
Denver, CO
60
9.8
3.9
3.4
17.1
Perryton, TX
30
2.3
0.3
0.8
3.4
Longview, TX
75
6.4
1.0
2.2
9.6
Bayfield, CO
26
2.2
0.4
0.8
3.3
Casper, WY
22
1.8
0.3
0.6
2.8
Elk City, OK
22
1.9
0.3
0.7
2.8
Rawlins, WY
14
1.1
0.2
0.4
1.7
Crosby, ND
14
1.0
0.2
0.4
1.6
Total
606
65.7
$            
18.8
$          
23.0
$          
107.5
$        

Net Income to Adjusted EBITDA Reconciliations
64
($ in millions)
Note:  Adjusted EBITDA is defined as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization and other non-cash and non-recurring items.
No Drilling
Core Asset
Business Plan
Gas Option Case
Net Income
(348.0)
(288.7)
(288.2)
(277.8)
(285.7)
(292.0)
+ / (-) Interest (Income) Expense
335.8
346.0
354.7
328.4
332.9
337.2
+ / (-) Income Tax Provision (Benefit)
(195.7)
(162.4)
(162.1)
(156.2)
(160.7)
(164.3)
+ DD&A
463.9
369.2
317.0
283.4
258.2
238.4
+ Accretion of Asset Retirement Obligation
2.4
-
-
-
-
-
+ Restructuring Charges
109.6
15.0
-
-
-
-
ADJUSTED EBITDA
368.0
279.1
221.3
177.8
144.7
119.3
FY
FY
FY
FY
FY
FY
2015
2016
2017
2018
2019
2020
Net Income
(348.0)
(274.2)
(234.1)
(208.1)
(207.4)
(208.2)
+ / (-) Interest (Income) Expense
335.8
346.0
354.7
328.4
332.9
337.2
+ / (-) Income Tax Provision (Benefit)
(195.7)
(154.3)
(131.7)
(117.1)
(116.7)
(117.1)
+ DD&A
463.9
410.5
427.2
428.8
417.8
405.4
+ Accretion of Asset Retirement Obligation
2.4
6.1
8.0
7.7
7.7
7.3
+ Restructuring Charges
109.6
15.0
-
-
-
-
ADJUSTED EBITDA
368.0
349.1
424.1
439.6
434.2
424.7
Net Income
(348.0)
(274.2)
(234.1)
(205.5)
(197.6)
(191.7)
+ / (-) Interest (Income) Expense
335.8
346.0
354.7
328.4
332.9
337.2
+ / (-) Income Tax Provision (Benefit)
(195.7)
(154.3)
(131.7)
(115.6)
(111.2)
(107.8)
+ DD&A
463.9
410.5
427.2
446.1
479.0
506.0
+ Accretion of Asset Retirement Obligation
2.4
6.1
8.0
8.4
9.3
9.0
+ Restructuring Charges
109.6
15.0
-
-
-
-
ADJUSTED EBITDA
368.0
349.1
424.1
461.8
512.3
552.8
FY
FY
FY
FY
FY
FY
2015
2016
2017
2018
2019
2020
FY
FY
FY
FY
FY
FY
2015
2016
2017
2018
2019
2020

Samson Resources Corp Reports