deutsche bank leveraged finance conference … overview 3 focus asset base add predictable, visible,...

Deutsche Bank Leveraged Finance Conference

September 30, 2014

2

Cautionary Statement Regarding Forward-Looking Statements

The information in this presentation by Samson Resources Corporation (the “Company,” “Samson,” “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) 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; (viii) restrictions contained in our debt agreements; (ix) our ability to generate sufficient cash to service our indebtedness; and (x) any of the risk factors and other cautionary statements described under the heading “Risk Factors” in the prospectus relating to the exchange offer of our senior notes, dated as of and filed with the Securities and Exchange Commission (the “SEC”) pursuant to Rule 424(b) under the Securities Act of 1933, as amended, on July 22, 2014, and the other documents and reports we 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 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.

Forward-Looking & Other Cautionary Statements

Company Overview

3

Focus Asset Base

Add Predictable, Visible, and High

Rate of Return Inventory

Enhance Liquidity

Strengthen and Protect the

Balance Sheet

Current Asset Base – Overview Map

Q2’14 Production: 197 MMcfe/d Proved Reserves(1): 652 Bcfe Net Acreage(2): 733,000

West Division

Q2’14 Production: 344 MMcfe/d Proved Reserves(1): 1,198 Bcfe Net Acreage(2): 856,000

East Division

Samson Active Plays Samson Corporate Offices (HQ: Tulsa, OK)

Total Co. Production(4) Q2’14: 543 MMcfe/d / Proved Reserves(1): 1.86 Tcfe with PV-10(3) of $2.8 Bn

(1) NSAI YE 2013 (Total Company proved reserves includes 7 Bcfe not included in the West and East Division totals) (2) Net Acreage as of 6/30/2014 (East and West Division totals do not include 134,000 net acres denoted as “Other”) (3) PV-10 is a non-GAAP financial measure. A reconciliation to its nearest GAAP financial measure is included in this presentation (4) Total Company production includes 2 MMcfe/d not included in the West and East Division totals

Corporate Strategy

$137

$205

$343

$179$161

$340

Q1'14 Q2'14 1H'14

Total Capex Adj EBITDA

Q2’14 production of 543 MMcfe/d, up 3% sequentially;

liquids production flat at 26.6 MBPD (29% liquids)

Q2’14 first sales activity up to 39 gross operated wells

from 26 in Q1’14; driven primarily by increased activity in

East Texas and the Powder River

Positive results from our first horizontal Cotton Valley

Taylor well – Texas Scottish Rite IP30 8.4 MMcfe/d

Successfully drilled first 2014 four-well Mississippi Lime

pad (completion in Q3)

Divested ~$110 million of non-core asset sales as of

8/31/14 – on track to meet or exceed $150 to $200 MM

target

4

Company Update

Total Capex(1) / Adjusted EBITDA(2)

Total Production

($MM)

(MMcfe/d) Recent Company Highlights

(1) Excludes capitalized cash interest and internal costs (2) Adjusted EBITDA is a non-GAAP financial measure. A reconciliation to its nearest GAAP financial

measure is included at the end of this presentation

425 409 385 370 384

170 174 158 159 160

596 582 543 529 543

Q2'13 Q3'13 Q4'13 Q1'14 Q2'14

Gas Liquids (Oil and NGL)

Note: Total Production, Total Capex and Adjusted EBITDA numbers are independently rounded

2014 Outlook

5

$670

~$600

Budget Capital Plan Current Capital PlanGas Oil NGL Total

362-396

530-580

89-97

79-87

FY 2014 Production Guidance FY 2014 D&C Capital Plan

1H’14 Actual: 537 MMcfe/d

1H’14 Actual: $330MM

1H’14 production impacted by underperformance in the Granite Wash and Ft. Union and shut-in volumes from offset completion activity from March through May

Current plan reflects reduced activity in the Granite Wash and Powder River

Teams expect to restart Granite Wash drilling in Q4’14 / Q1’15 timeframe

(MMcfe/d) ($MM)

Business Unit Overview

Greater Green River – Ft. Union continue to delineate

Powder River – Exploration and development of

multiple prospective oil horizons

San Juan – Mature dry gas position / focus on

optimization

Williston – Bakken and Three Forks horizontal oil

development

Rig Count: 4 rigs (1 PRB / 1 Williston / 2 Ft. Union(1))

Net Acreage(2): 733,000

Q2’14 Production: 197 MMcfe/d (38% Liquids)

Proved Reserves(3): 652 Bcfe

Q2’14 Production: 80 MMcfe/d Net Acreage: 61,000

San Juan

Overview Map

WYOMING

COLORADO

NORTH DAKOTA


Greater Green River


Powder River


Williston

West Division

6

(1) Ft. Union seven month drilling season (August through February) (2) Net Acreage as of 6/30/2014 (3) NSAI YE 2013

Overview – Ft. Union

Liquids rich gas play with high impact potential

Targeting three intervals of stacked sand with approximately 1,000 feet of gross interval (TVD 9,800’ to 10,800’)

Nine gross operated horizontal wells producing as of Q2’14 (one Upper, six Middle and two Lower)

Samson is the primary operator in play with an average working interest of approximately 80%

Current Operations

2014-2015 drilling plan consists of:

Five gross operated horizontal Middle wells designed to test stacked laterals, spacing and field extent; and

Six gross operated vertical wells focused on delineation and isolated zone testing

Rig Count: 2 rigs (seasonal drilling(2))

Net Acreage (Ft. Union only): ~32,000

Greater Green River – Ft. Union

Overview Map – Ft. Union

PRODUCING HZ PRODUCING VERTICAL 2014-2015 DRILL WINDOW HZ 2014-2015 DRILL WINDOW VERTICAL

Barricade Unit

Endurance Unit

7

Endurance 41-29 (3-Well Pad)

First Sales: Feb ‘14

Barricade 24-36 (3-Well Pad)(1)

First Sales: Mar ‘14

(1) 24-36 S1MH was not completed during the 2013-2014 drill window due to down hole mechanical issues (2) Ft. Union seven month drilling season (August through February)

0.4 0.3 0.4 0.3 0.3

3.5 3.3 3.0 3.3

4.4

3.9 3.6 3.5 3.6

4.7

Q2'13 Q3'13 Q4'13 Q1'14 Q2'14

Total Production(MBoe/d)


2014 Operations Update:

Multiple pay basin characterized by conventional (Shannon, Sussex, Frontier, Parkman) and unconventional (Mowry, Niobrara) oil targets ranging from 7,500’- 13,000’ TVD

Industry remains active in basin with approximately 30 rigs as of August ’14 (11 Frontier/Turner; 7 Parkman; 5 Shannon/Sussex; 2 Niobrara, ~5 Other)

2H’14 Samson activity focused on drilling two mile horizontal Sussex laterals in Hornbuckle and Spearhead fields

Rig Count: 1 rig

Net Acreage: 299,000(1)

Overview Map

Powder River

JOHNSON

CAMPBELL

CONVERSE

8

North Tree - Shannon

SAMSON ACTIVE RIG

(1) Currently focused on 107,000 net acres targeting Shannon, Sussex, Frontier and Mowry

Note: Peer logo’s represent area drilling activity as of August 2014

Spearhead/Hornbuckle - Sussex

Williston

9

Ambrose Field

Bel Air 7H & Comet 7H Producing P&P Test First Sales: Q2’14


One rig program focused on infill development of the Bakken and Three Forks formations in Ambrose Field

Nine gross operated wells delivered to sales during Q2’14

First test combining plug & perf completion and increased spacing concept expected to go to sales in Q3’14

2H’14 activity solely focused on new completion and spacing approach

Rig Count: 1 rig

Net Acreage: 127,000 (Divide County, ND – 71,000)

Overview Map

ACTIVE RIG OPERATED ACREAGE

NON-OP ACREAGE

Marauder/Stingray/Charger P&P + Spacing Test

4-Well Pad First Sales Est: Q3’14

DIVIDE

PRODUCING SPACING TEST 0.2 0.2 0.3

4.5 4.1 3.9 3.6 3.8

4.5 4.2

4.0 3.8

4.1

Q2'13 Q3'13 Q4'13 Q1'14 Q2'14

Total Production(MBoe/d)


Q2’14 Production: 157 MMcfe/d


East Texas


Net Acreage: 304,000

Mid-Continent East Overview Map Business Unit Overview

East Texas – horizontal delineation and development

of the Cotton Valley and Taylor sands

Mid-Continent West – Updating geologic and

reservoir models for 12 Granite Wash horizons

Mid-Continent East – Early delineation and

assessment of Mississippi Lime potential

Rig Count: 5 rigs (1 MCW/ 2 MCE / 2 ET)


Q2’14 Production: 344 MMcfe/d (25% Liquids)

Proved Reserves(3): 1,198 Bcfe



Mid-Continent West

East Division

10

TEXAS

OKLAHOMA

GRANITE WASH PLAY

MISSISSIPPI LIME PLAY

COTTON VALLEY & HAYNESVILLE PLAYS

(1) Net Acreage as of 6/30/2014 (2) East Texas includes 67,000 net mineral acres in the Permian Basin (3) NSAI YE 2013

2014 Operations Update – Cotton Valley

Optimizing legacy leasehold position through transition to horizontal development of the Cotton Valley Sands – approximately 60 gross operated horizontal and 550 gross operated vertical Cotton Valley wells producing as of Aug ’14

Re-started the Cotton Valley Taylor play with a four well horizontal pilot program in 2014; initial results have been positive

2H’14 will focus on continued development of Cotton Valley C sands at Southeast Carthage and delineation of the Taylor program

Rig Count: 2 rigs

Net Acreage: 345,000 (Cotton Valley(1) – 74,000)

East Texas

11 (1) Focused in Panola, Rusk, Harrison and Gregg counties

Overview Map – Cotton Valley

Active Rigs

HARRISON

PANOLA RUSK

GREGG

Cotton Valley Taylor Horizontal

Texas Scottish Rite #2H (Cotton Valley Taylor) First Sales: May ‘14

IP30: 7.3 MMcf/d & 175 BOPD

Texas

Oklahoma

148 141 140 126 135

26 20 20

22 23

175 161 161

148 157

Q2'13 Q3'13 Q4'13 Q1'14 Q2'14

Total Production(MMcfe/d)

Gas Liquids (Oil and NGL) Cotton Valley

52 52 48 47 51

43 45 40 37 33

94 97 88 84 84

Q2'13 Q3'13 Q4'13 Q1'14 Q2'14



Mid-Continent West

12

Hemphill

Lipscomb

Ochiltree

Roberts

Wheeler

Granite Wash

(1) Focused in Wheeler, Hemphill and Roberts counties (2) IP 30 post frac sleeve clean-out


Eleven horizontal Granite Wash wells delivered to sales

1H’14; overall results below expectations

Updating geologic and engineering models for all 12

stacked horizons with expected re-entry Q4‘14 or

Q1’15 – focused primarily on single well horizontals

Q3’14 drilling Cleveland oil horizontals in Ochiltree

County, TX

Rig Count: 1 rig

Net Acreage: 207,000 (Granite Wash(1) – 57,000)

Overview Map – Granite Wash

Meadows (2-Well Pad) 31-5H UGW Yellow

D&C: $7.1MM IP 30: 4.3 MMcf/d & 100 BOPD

Texas

Oklahoma

TEX

AS

OK

LAH

OM

A

RECENT HORIZONTAL MULTI-WELL PADS

Pounds (2-Well Pad) 18-6H UGW Dark Green

D&C: $5.9MM IP 30(2): 5.5 MMcf/d & 230 BOPD

Lister (3-Well Pad) 602 UGW Red D&C: $6.7MM

IP 30: 4.5 MMcf/d & 520 BOPD

8,7

00

-13,000 TV

D

Do

ugl

ass

Douglass

Cottage Grove

Hogshooter

Purple

Red

Yellow

Dark Green

Dark Blue

Upper Pink

Lower Pink

Light Green

Orange

Up

per

Gra

nit

e W

ash

Low

er G

ran

ite

Was

hC

her

oke

e

Was

h

OPERATED ACREAGE

NON-OP ACREAGE

Mid-Continent East

13

Overview Map – Mississippi Lime

Active Rigs

Woods

Alfalfa

Dietz Area

Shawna/Dietz (4-Well Pad) 2 Upper & 2 Lower

D&C: $4.4MM First Sales: Aug ‘14

Producing

Waiting on Completion 68 72 71 75 73

22 30 31

35 30

90

102 102 110

103

Q2'13 Q3'13 Q4'13 Q1'14 Q2'14




Current drilling activity focused on the Mississippi Lime play – targeting both the Upper and Lower zones

Ten horizontal wells producing in our Dietz area with five wells delivered to first sales during Q3’14

Initial results on the Shawna/Dietz pad are positive

2H’14 continue one rig program

Rig Count: 2 rigs (1 Marmaton / 1 MS Lime)


Balance Sheet

Adequate liquidity position

Simple capital structure with no near-term maturities

Bank Credit Facility

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

Borrowing base of $1.0 billion

Recently amended RBL to provide additional financial flexibility

Hedge Position

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

Over 80% hedged on a total hydrocarbons basis for CY 2014

Initial positions established for 2015

Financial Position

14

$500 $500

$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

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

(1)

($MM)

Debt Maturity Profile and Liquidity

Debt Maturity Profile and Liquidity

RBL Capacity: $1.0 BN

15

Highlights

Revolver availability(1) of $500 MM as of June 30, 2014

Ability to incur incremental $500 MM of second lien debt without a related Borrowing Base reduction

Debt Tranches

Sr. Notes – $2.25BN

Due February 2020 Coupon 9.75%

8 year / NC 4

2nd Lien Term Loan – $1.0 BN

Due September 2018 Libor plus 4.00% (LF = 1.00%)

RBL Credit Facility

Matures December 2016 Borrowing Base $1.0 BN Grid based rates (1.50%-2.50%) Financial Performance Covenant –

First Lien Net Debt to LTM Covenant Adjusted EBITDA no greater than 1.5x through Q4’15

As of September 25, 2014

(1) Volumes are rounded (2) 2015 includes 20,000 MMBtu/d of Cal ’15 collars and 10,000 MMBtu/d of Q1’15 collars (3) 2016 includes 30,000 MMBtu/d of natural gas collars to the extent our counterparty elects to exercise their collar options Note: 2014 includes balance of the year only

Year Bbls/d(1) Swap Price

2014 15,000 $90.62

2015 3,500 $90.91

Year Bbls/d(1) Swap Price

2014 7,500 $35.42

2015 750 $37.07

Year MMBtu/d(1) Wtd Avg

Floor

2014 306,000 $4.15

2015(2) 192,000 $4.05

2016(3) 161,000 $4.04

2017 40,000 $3.92

NGL Swaps Oil Swaps Natural Gas Swaps & Collars

Current Hedge Position

16

Attract and Retain Quality People

Optimize Capital Program

Add Additional Future Drill Bit Inventory

Strengthen and Protect the Balance Sheet

Position Company for Access to Additional Sources of Capital

Summary

17

18

EBITDA, Adjusted EBITDA, Covenant Adjusted EBITDA and PV-10 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. 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 provide 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. The standardized measure of discounted future net cash flows is the most directly comparable GAAP financial measure to each of PV-10 and PV-10 after ARO. 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 EBITDA, Adjusted EBITDA, Covenant Adjusted EBITDA, PV-10 and PV-10 after ARO 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 tables present reconciliations of these non-GAAP financial measures to their most directly comparable GAAP financial measures on a historical basis for each of the periods indicated.

Non-GAAP Disclosures

19 Note: Calculated as of 6/30/14 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

Q2 2014 Adjusted EBITDA Reconciliation

Three Months Twelve Months

Ended Ended

June 30, 2014 June 30, 2014

(dollars in thousands)

Net income (loss) (207,822)$ (1,339,033)$

Interest expense, net 21,443 41,919

Provision (benefit) for income taxes (115,146) (743,200)

Depreciation, depletion and amortization 128,189 549,217

EBITDA (173,336)$ (1,491,097)$

Adjustment for unrealized hedging losses (gains) 3,279 82,320

Adjustment for non-cash stock compensation expense 10,392 41,818

Adjustment for fees paid to sponsors 5,513 21,525

Adjustment for fees paid for public company compliance 586 1,708

(Gain) loss on sale of other property and equipment 95 (2,431)

Provision to reduce carrying value of oil and gas properties 312,070 2,049,410

Unusual or non-recurring charges described in credit agreement 2,729 18,497

Adjusted EBITDA 161,328$ 721,750$

Covenant Adjusted EBITDA 712,874$

(1) Includes depreciation, depletion and amortization of oil and gas properties and depreciation and amortization of other property and equipment and accretion of asset retirement obligations (2) Stock compensation expense recognized in earnings, net of capitalization (3) Quarterly management fee (4) Excludes sold Adjusted EBITDA of approximately $8.9 MM 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

(1)

(2)

(3)

(4)

20

PV-10 Reconciliation

(dollars in thousands)

As of December 31,

2013 PV-10 $2,815,239

Present value of estimated ARO, discounted at 10% (29,260) PV-10 after ARO 2,785,979 Present value of future income tax, discounted at 10% (173,292) Standardized measure of discounted future net cash flows $2,612,687

deutsche bank leveraged finance conference … overview 3 focus asset base add predictable, visible,...

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