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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
Q2’14 Production: 64 MMcfe/d Net Acreage: 246,000
Greater Green River
Q2’14 Production: 29 MMcfe/d Net Acreage: 299,000
Powder River
Q2’14 Production: 24 MMcfe/d Net Acreage: 127,000
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)
Gas Liquids (Oil and NGL)
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
2014 Operations Update:
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)
Gas Liquids (Oil and NGL)
Q2’14 Production: 157 MMcfe/d
Net Acreage(2): 345,000
East Texas
Q2’14 Production: 103 MMcfe/d
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)
Net Acreage(1): 856,000
Q2’14 Production: 344 MMcfe/d (25% Liquids)
Proved Reserves(3): 1,198 Bcfe
Q2’14 Production: 84 MMcfe/d
Net Acreage: 207,000
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
Total Production(MMcfe/d)
Gas Liquids (Oil and NGL)
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
2014 Operations Update:
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
Total Production(MMcfe/d)
Gas Liquids (Oil and NGL)
2014 Operations Update:
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)
Net Acreage: 304,000
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
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