Samson Resources 8-K Forward-Looking & Other Cautionary Statements

Year-End 2014 Conference Call

April 1, 2015

Supplemental Materials

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Exhibit 99.1

2

Forward-Looking & Other Cautionary Statements

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.

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.

Key Strategic Initiatives

3

2015 Objectives

Recent Actions

Amended credit facility to preserve near-

term liquidity

Creates runway from which to

implement a comprehensive

restructuring

Ceased drilling

Recent completions and operational

performance improvements

Sold Arkoma assets

Proceeds of $48 MM

Reduced workforce by approximately 30%

and implemented other cost cutting

initiatives

Hired advisors to facilitate debt restructuring

Retain key technical and professional

talent

Further reduce costs

Continue program to upgrade key facilities

Continue asset evaluations and potential

sales of non-core assets

Achieve permanent changes to our capital

structure

Rationalize debt load to match asset

base and current performance

4

2014 Financial & Operating Metrics

(2)

(3)

(4)

(1)

(1)

Including realized derivatives

(2)

Income Statement G&A excluding stock-based G&A compensation expenses of $0.27 and $0.12 per Mcfe for the year ended December 31, 2014 and December 31, 2013, respectively, and $0.43 and $0.24 

per Mcfe for the three months ended December 31, 2014 and September 30, 2014, respectively.  Note: CY 2014 Cash G&A includes one time cash incentive compensation of $0.04 per Mcfe

(3)

Cash operating margin is a non-GAAP financial measure.  A description of cash operating margin is included at the end of this presentation and the calculation of the measure is provided above.

(4)

Adjusted EBITDA is a non-GAAP financial measure.  A reconciliation to its nearest GAAP financial measure is included at the end of this presentation.

2014

2013

Q4'14

Q3'14

Production (MMcfe/d)

530

578

515

530

Realized Price ($/Mcfe)

$5.43

$5.32

$5.12

$5.61

Operating Expenses ($/Mcfe)

LOE

$1.09

$0.93

$1.14

$1.12

Production Tax

$0.41

$0.36

$0.30

$0.45

Cash G&A

$0.64

$0.50

$0.75

$0.60

Total

$2.14

$1.79

$2.19

$2.17

Cash Operating Margin ($/Mcfe)

$3.29

$3.53

$2.93

$3.44

Adjusted EBITDA ($MM)

$663

$775

$148

$175

5

2014 Free Cash Flow & Net Debt

($MM)

2014

2013

Q4'14

Q3'14

Cash Flow From Operations

$488

$689

$124

$103

Divestiture Proceeds

$157

$317

$42

$61

Total

$644

$1,005

$167

$164

Cash Capital Expenditures:

Drilling and Completion

$594

$667

$142

$121

Acquisitions

$58

$0

$58

$0

LGG, Facility & Other

$41

$84

$18

$11

Capitalized Cash Interest & Internal Costs

$276

$330

$16

$109

Total

$969

$1,081

$233

$241

Free Cash Flow Before Financing Activities

(1)

($325)

($76)

($67)

($78)

Net Debt

(2)

$3,881

$3,553

Note:  Totals may not sum due to independent rounding

(1)

Reflects net cash provided by operating activities plus net cash used in investing activities

(2)

Long-term debt (including debt classified as current) less cash and cash equivalents

March 2015 RBL Amendment Detail

6

6

Previous

Current

Borrowing Base ($MM)

$1,000

$950

Commitment Amount ($MM)

$2,250

Borrowing Base ($950)

Drawn Pricing (LIBOR Spread)

150 -

250 bps

200 -

300 bps

"Going Concern" Certification Requirement for YE 2014

Financials

Yes

Waived

Pro-Forma Liquidity Requirement To Service Junior Debt

(Beginning July 1, 2015)

No

$150 MM

First Lien Debt / EBITDA Covenant:

Through Q3'15

1.50x

2.75x

Q4'15

1.50x

1.50x

Total Debt / EBITDA Covenant:

Q1'16

4.50x

4.50x

Borrowing Base Reduction Related to Asset Sales

Subject to Collateral Coverage; Triggered

for Aggregate Asset Sales in Excess of 5%

Automatic Reduction Equal to Net Cash

Proceeds Received with the Exception of

Non-Core Mid-Con and Permian Minerals,

whereby Reduction Equal to the Greater of

(i) 100% of Bank PV-9 or (ii) 75% of Net

Cash Proceeds Received

Lender Consent Required for Borrowing Base Increase

90%

100%

Cost Reduction Initiatives

7

7

Currently in the midst of comprehensive cost-reduction efforts to decrease headcount and non-headcount

general and administrative expenses and operating costs

One time costs offset current year efficiency gains

Yearly run-rate reduction is projected to be approximately $60 MM

Unlikely to have significant positive impact on near-term liquidity

Implemented reduction of force affecting approximately 30% of employees in March 2015

Currently evaluating field operations personnel, which will be complete in approximately four weeks and

will result in reductions

One time severance costs of approximately $30 MM

Plan to achieve run-rate cash G&A savings of  $60 MM

Divestiture Strategy

2013 –

Q1 2015 Divestitures

Asset Sale Update

Executed Arkoma divestiture for $48 MM

(1)(2)

Bakken, Wamsutter, San Juan, Permian Minerals

and Non-Core Mid-Con assets marketed, but did

not receive acceptable bids

Ability to efficiently re-initiate sales process

under more favorable price environment

Continue to evaluate non-core assets in order to

optimize the portfolio 

Under RBL amendment, any sale proceeds

received would reduce borrowing base capacity on

a dollar-for-dollar basis, except for our Non-Core

Mid-Con and Permian Minerals

(3)

Year

Proceeds

No. of

Transactions

2013

$317 MM

56

2014

$157 MM

111

Q1’15

~$59 MM

(2)

6

8

(1)

Closed on March 13, 2015

(2)

Excludes post closing adjustments 

(3)

Non-Core Mid-Con and Permian Minerals divestitures trigger reduction equal to the greater of Bank PV-9 or 75% of the Net Cash Proceeds.  Refer to Slide 6 for detail.

Current Hedge Position

Year

Bbls/d

(1)

Swap Price

2015

3,500

$90.91

Year

Bbls/d

(1)

Swap Price

2015

750

$37.07

Year

MMBtu/d

(1)

Wtd Avg

Floor

2015

(2)

186,000

$4.04

2016

(3)

161,000

$4.04

2017

40,000

$3.92

NGL Swaps

Oil Swaps

Natural Gas Swaps & Collars

(1)

Volumes are rounded.

(2)

2015 includes 20,000 MMBtu/d of CY 2015 collars.

(3)

2016 includes 30,000 MMBtu/d of natural gas collars to the extent our counterparty elects to exercise their collar options.

Note:  2015 includes balance of the year only

As of March 13, 2015

Mark to Market Value of Approximately $150 MM (~$100 MM associated with 2015)

9

2014 Production and Capital Summary

2014 Oil and Gas Capital By Type

(3)

($MM)

10

2014 Total Production of 530 MMcfe/d

2014 Pro Forma Total Production of 518 MMcfe/d

(2)

30% Liquids

(2)

CY 2014 vs. CY 2013 YoY decline of 5%

(2)

Total Oil & Gas Capital spend of $635 MM

94% D&C

Non-D&C Oil and Gas Capital of $41 MM

$28 MM in Facilities / Other

$13 MM in LG&G

2014 Production By Quarter

(MMcfe/d)

(1)

Includes Arkoma through the close date

(2)

Pro Forma for 2013 and 2014 closed divestitures

(3)

Excludes acquisition capital

2014 Reserve Summary

11

Key Highlights:

Total Proved Reserves Bridge

Total Proved Reserves

(1)

:  1.5 Tcfe

73% Gas

84% PDP

Total PV-10

(2)

: 

SEC Pricing:  $2.6 billion

3/13 NYMEX Strip:  $1.3 billion

Cost to Develop

(3)

:  $2.71 / Mcfe

Finding & Development

(4)

:  $3.86 / Mcfe

Reserve Replacement

(5)

: 77%

Gas: 63%

Oil: 112%

NGL: 105%

Proved Developed

Proved Undeveloped

(YE’13 vs. YE’14)

(1)

Year End 2014 NSAI Reserve Report. Note:  SEC Pricing – Oil $94.99, Gas $4.35, NGL $33.46

(2)

PV-10 is a non-GAAP financial measure. A reconciliation to its nearest GAAP financial measure is included in this presentation. 

(3)

Cost to Develop calculated as $558 MM of drilling and completion capital divided by 206 Bcfe, which consists of 126 Bcfe of PUD to PDP conversions and 80 Bcfe of non-proved to PDP conversions

(4)

Finding & Development calculated as $558 MM of drilling and completion capital plus $13.4 MM of LGG capital divided by 148 Bcfe of Extensions and Discoveries

(5)

Extensions and Discoveries divided by Production

Note: 3/13 NYMEX Strip (Five Year Average) – Oil $59.79; Gas $3.32; NGL $21.06

12

Operated Well Results:  2014 Spuds

PV10: $87 MM

Total capital incurred of approximately

$345 MM

Program PV10 of $87 MM

Core Assets added approximately

$129 MM

Other assets dilutive in aggregate

71 operated wells spud in 2014

Operated Well Results:  2014 Spuds

Note:  Return on investment reflects SEC Pricing.  SEC Pricing – Oil $94.99, Gas $4.35, NGL $33.46

13

Operated Well Results:  Core Assets

East Texas

Operated Well Results:  2014 Spuds

Williston

Operated Wells Results:  2014 Spuds

PV10: $95 MM

PV10: $34 MM

Note:  Return on investment reflects SEC Pricing.  SEC Pricing – Oil $94.99, Gas $4.35, NGL $33.46

Portfolio Characterization

14

Core

Assess Upside

Divest

Characteristics

Plays

Three Key Categories

Bakken/Three Forks

Taylor

Cotton Valley

Haynesville (Gas

Option)

Ft. Union

Granite Wash

Mowry

Non-Core Midcon

San Juan

Wamsutter

Permian Minerals

High well count

Limited upside

Scattered position

High Non-Op ratio

Not part of future core

area

Potential growth assets

Subsurface/execution

complexity

Demonstrate repeatability

Manage risk to prove up

commerciality

Predictable

Repeatable

Consolidated position

Opportunity to bolt-on

(East Texas)

Go-Forward

Plan

Re-initiate drilling

under sufficient macro

price & cost

environment

Calculated approach

to testing

Divest assets when

appropriate

Forward Focused Development

Recent Highlights

Core

Assess Upside

15

Williston -

Bakken/Three Forks

Changed to plug & perf completions

Reduced number of laterals per DSU

Resulted in +50% increase in IP30 and EUR’s

East Texas -

Taylor appraisal program success

7 wells proved-up play

EUR’s average 6.0+ BCFE (24% liquids)

East Texas -

Cotton Valley C1 target success

Significant increase in EUR’s compared to stacked targets

Higher liquid yields & lower water production

Have

drilled

up

to

7,600’

laterals

(avg

6,000’)

Fort Union significant reservoir capacity

Early rates 8-16 MMcfe/d, 10-20% liquids

Drilling execution remains a challenge

Continue to advance technical understanding of complex play

Mowry Pilot early optimism

Early data indicates attractive resource play parameters

Preliminary core & vertical test confirms play concept

Granite Wash

Early days of testing based on improved technical evaluation

16

Operated Rates of Return: Lower Price Environment

10%

20%

30%

Target Formations

Cotton Valley

Williston

Fort Union

Taylor

Granite Wash

Haynesville

Note:  Lower Price Environment Rates of Return (ROR) calculated with flat $3.50/Mcf gas, $65/Bbl oil and 3/13 NYMEX Strip (Five Year Average) – Oil $59.79; Gas $3.32; NGL $21.06

Addressing Challenges and Improving Results

17

Q3 2013

Q4 2013

Q1 2014

Q2 2014

Q3 2014

Q4 2014

Q1 2015

•

“Cracked

the

code”

in

Williston

with

change in completion methodology,

EUR’s +50%

•

Fort Union reservoir capacity

confirmed, studies commissioned to

reduce drilling issues and advance

knowledge on optimal development

•

Powder River Program

curtailed (3 rigs to 1 rig)

due to inconsistent results

•

Granite Wash Program

halted

•

Reorganized staff to

enhance technical work

•

Encouraging Mowry Pilot

•

Cotton Valley C1 Target

success

•

Mixed results from Fort

Union Program

•

Granite Wash Program

selectively restarted

•

Began Cotton Valley C1 Program

•

Powder River (Shannon/Sussex)

Program halted

•

East Texas begins focus on

Taylor delineation

•

Williston Program reassessed in

light of underperformance

•

Marmaton drilling curtailed

•

Implemented controlled lease

acquisition approach

•

Began detailed review of

assets

East Texas Update

East Texas Update

Taylor Sand Highlights

Re-initiated CV / Taylor drilling program

De-risked / Delineated future Taylor inventory

2014 Taylor program average EUR +6.0 BCFE (24% liquids)

Strong results helps solidify significant Taylor inventory

C Target

(Lower Stack)

B Target

(Upper Stack)

Top CNVL

1200’

to base

of C2 Sand

SE Carthage Field

18

Cotton Valley Highlights

Transitioned from stacked Cotton Valley

laterals to single target

Previously drilled 2 wells averaging $6.2MM

CWC & 5.1 BCFE each

Recent single target results have averaged 

$6.0MM and 7.5 BCFE each

Improved drilling & completion techniques in

both Taylor & Cotton Valley allowing for

extended lateral lengths

2014 Record lateral: 7,615’

Improved clean-out efficiencies

through use of dissolvable plugs

Assessing impact from increased frac

size

Stacked Lateral

10.2 BCFE  (2 wells)

30% Liq

C1 Targets

Avg  8.6 BCFE/well

35% Liq

C1 Targets

Avg 9.0 BCFE/well 

30% Liq

(New Target)

CNVL  Stacked C2-B2 Targets

CNVL C1 Sand Target

19

Williston Update

Increased spacing

Changed completion design to plug & perf

EUR & IP30 improved by ~50%

Good results with new approach throughout our

acreage

Samson Williston Wells to Date

Plug & Perf Wells

Avg Plug & Perf

Sliding Sleeve Wells

Avg Sliding Sleeve

Cumulative Fluid vs Producing Days

Williston Highlights

Open Hole Packer

Sliding Sleeves

Cemented Liners,

Plug and

Perforations

OPERATED

ACREAGE

NON-OP

ACREAGE

Beetle 3H, Strom 8H,

Ranchero 2H, Coronet 8H 

Avg EUR 383 Mboe

Ranchero 6H, Ranchero 8H

Currently completing

Ness 4H, Ness 6H,

Odyssey 6H

First oil end of Feb.

Stingray 6H,

Charger 8H

Avg EUR 427 Mboe

Dorado 6H, Dorado 8H

First oil mid Mar.

Marauder 1H, Marauder 3H

Avg EUR 438 Mboe

Ambrose Field -

Development

Count of Wells on Production (2014 program)

0-60 days

60-120 days

120-180 days

180+ days

Plug &

Perf

11

4

4

0

Sliding

Sleeve

4

4

4

4

2015E Production and Capital Plan

No additional first sales expected after early

April

Capital By Type

(1)

($MM)

(1)

Excludes capitalized interest and internal costs.  Non-D&C includes LGG $12 MM, facilities/production operations $25 MM, rig penalties/prepayments $16 MM, and corporate/other $10 MM

(2)

Guidance net of Arkoma post close date

Production Guidance

(2)

(MMcfe/d)

20

Overview

2015 Production Guidance: 435 to 460 MMcfe/d

2015 Total Oil & Gas Capital Plan:  $156 MM

Turning ~30 wells to first sales in early 2015,

primarily as a result of 2014 spud activity

Continued spend on critical facilities to manage

EHS considerations

Organizational focus on production optimization,

cost management and efficiency

Portfolio Resource Potential

21

Note: Graph depicts high-end of resource potential

Key Takeaways

22

RBL Amendment creates runway to implement more comprehensive restructuring

Significant operational changes completed with further savings possible

Meaningful growth opportunities if pricing improves modestly

Company focused on addressing capital structure to unlock long-term value and match liabilities to

assets and cash flows

Expect many acquisition opportunities if company can de-lever balance sheet quickly

Strong management team and key employees in place to execute go-forward strategy

23

Non-GAAP Disclosures

Cash operating margin, EBITDA, Adjusted EBITDA and Covenant Adjusted EBITDA are non-GAAP financial measures. We believe that the presentation of these non-GAAP

financial measures will provide useful information to investors in assessing our financial condition and results of operations.

Cash operating margin represents our average realized sales price per Mcfe, including the effect of realized derivatives,  less (i) lease operating expenses per Mcfe, (ii)

production and ad valorem taxes per Mcfe and (iii) general and administrative expenses per Mcfe, excluding stock based compensation expenses. The per unit components of 

cash operating margin are determined by dividing the applicable component by our total production on a natural gas equivalent basis. We believe that  cash operating margin is

an important measure that can facilitate comparisons of our performance between periods and to the performance of our peer companies.

EBITDA is defined as net income (loss) before interest expense, income tax expense (benefit), depreciation and amortization. Adjusted EBITDA represents EBITDA adjusted as

applicable in the relevant period for select items specified in the credit agreement governing our revolving credit facility, including unrealized hedging losses (gains), non-cash

stock compensation expenses, management and similar fees paid to our sponsors, costs associated with the preparation and implementation of certain public company

compliance obligations, losses (gains) on non-ordinary course asset dispositions, ceiling test charges and certain unusual and non-recurring charges. We define Covenant

Adjusted EBITDA as total Adjusted EBITDA less the Adjusted EBITDA attributable to any assets or businesses disposed of during the relevant period. We believe that the

presentation of EBITDA, Adjusted EBITDA and Covenant Adjusted EBITDA is important to provide management and investors with (i) additional information to evaluate our

ability to service and comply with our debt obligations, adjusting for certain items required or permitted in calculating covenant compliance under the credit agreement

governing our revolving credit facility, (ii) a supplemental indicator of the operational performance and value of our business, (iii) an additional criterion for evaluating our

performance relative to peer companies and (iv) supplemental information about certain material non-cash and other items that may not continue at the same level in the

future.

We refer to PV-10 as the present value of estimated future net cash flows of estimated proved reserves as calculated in the respective reserve report using a discount rate of

10%. This amount includes projected revenues, estimated production costs and estimated future development costs and excludes the estimated cash flows related to future

asset retirement obligations (“ARO”) and future income taxes. We have also included PV-10 after ARO below. PV-10 after ARO includes the present value of ARO related to

proved reserves using a 10% discount rate and no inflation of current costs. We believe that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and

useful for evaluating the relative monetary significance of our proved oil and natural gas reserves. We believe the use of pre-tax measures is valuable because there are many

unique factors that can impact an individual company when estimating the amount of future income taxes to be paid. Management believes that the presentation of these

measures provides useful information to investors because they are widely used by investors in evaluating oil and natural gas companies. 

Net income (loss) is the GAAP financial measure most directly comparable to each of EBITDA, Adjusted EBITDA and Covenant Adjusted EBITDA. Our non-GAAP financial measures

should not be considered as alternatives to the most directly comparable GAAP financial measures. Each of these non-GAAP financial measures has important limitations as an

analytical tool because it excludes some, but not all, items that affect the most directly comparable GAAP financial measure. You should not consider these non-GAAP financial

measures in isolation or as a substitute for analysis of our results as reported under GAAP. Because  cash operating margin, EBITDA, Adjusted EBITDA and Covenant Adjusted

EBITDA may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures

of other companies, thereby diminishing their utility.

Management compensates for the limitations of these non-GAAP financial measures as an analytical tool by reviewing the comparable GAAP financial measures, understanding

the difference between the non-GAAP financial measures, on the one hand, and each of their respective most directly comparable GAAP financial measures, on the other hand,

and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management

uses in evaluating our financial condition and results of operations.

The following table presents reconciliations of EBITDA, Adjusted EBITDA and Covenant Adjusted EBITDA to net income (loss) for each of the periods indicated. 

24

PV-10 Reconciliation

(dollars in thousands)

As of

December

31,

2014

PV-10

$2,551,402

Present value of estimated ARO, discounted at 10%

(34,011)

PV-10 after ARO

2,517,391

Present value of future income tax, discounted at 10%

(262,111)

Standardized measure of discounted future net cash flows

$2,255,280

25

2014 Adjusted EBITDA Reconciliation

Three Months

Twelve Months

Ended

Ended

December 31, 2014

December 31, 2014

Net income (loss)

(949,924)

$                    

(1,420,581)

$              

Interest expense, net

26,213

91,908

Provision (benefit) for income taxes

(528,657)

(789,519)

Depreciation, depletion and amortization

(1)

113,248

483,492

EBITDA

(1,339,120)

$               

(1,634,700)

$              

Adjustment for unrealized hedging losses (gains)

(82,639)

(128,038)

Adjustment for non-cash stock compensation expense

(2)

16,683

51,518

Adjustment for fees paid to co-investors

(3)

5,512

22,050

Adjustment for fees paid for public company compliance

1,353

3,046

(Gain) loss on sale of other property and equipment

164

1,211

Provision to reduce carrying value of oil and gas properties

1,534,809

2,325,346

Unusual or non-recurring charges described in credit agreement

10,866

22,801

Adjusted EBITDA

147,628

$                     

663,234

$                    

Covenant Adjusted EBITDA

(4)

664,357

$                    

(1)

Includes depreciation, depletion and amortization of oil and gas properties and depreciation and amortization of other property and equipment and accretion of ARO

(2)

Stock compensation expense recognized in earnings, net of capitalization

(3)

Quarterly management fee

(4)

Incorporates net adjustment of approximately $1 MM to account for acquired and divested EBITDA, as per the credit agreement governing our revolving credit facility. Covenant Adjusted EBITDA

measured on a rolling four-quarters basis is used to determine our compliance with the financial performance covenant in the credit agreement governing our revolving credit facility.

Note:  Calculated as of 12/31/14 with respect to Samson Resources Corporation and its consolidated subsidiaries by reference to the applicable terms of the credit agreement governing our revolving

credit facility