august 2013 - samson resources€¦ · samson rigs producing wells rig count: currently no active...

August 2013

East Texas 177

Mid-Con 185

Rockies 233

PDNP 1%

PDP 64%

PUD 35%

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

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

Q2 2013 Production: 595 MMcfe/d

Operated Rigs: 11

Total Net Acres: ~2.2 million

Company Overview

Rockies Division Targets: Shannon, Sussex, Frontier, Three Forks, Middle Bakken, Ft. Union

Mid-Continent Division Targets: Marmaton, Granite Wash, Hogshooter / Cottage Grove Wash

Samson Rigs

East Texas Division Active Targets: Cotton Valley Sands Gas Option: Haynesville

2

Q2 Production by Division

Reserves by Category

(MMcfe/d)

3

Corporate Strategy Maximize dollars at the drill bit

Focus on prospects with higher liquids content (returns focused drilling program)

Reduction in leasehold, geological and geophysical spending

Reduce costs and improve efficiencies in the field – cost focus drives economic viability of

marginal drilling programs

Delineate the Granite Wash and Ft. Union positions

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

Bolt-on to existing core positions with advantaged economics (Mid-Con / East Texas)

Lower exploration risk

Well hedged on oil and natural gas for the next 18 – 24 months. Program protects near-term

capital plan

Incremental non-core assets sales – divested over $100 million of non-core properties YTD, on

track to divest another $200 million by year end

Equity contribution to fund growth from acquisitions or acceleration of delineated inventory

Position portfolio for public market access

Optimize Capital Program

Future Drill Bit Inventory

Protect the Balance Sheet in Short Term

Long Term Opportunities to

Strengthen Balance Sheet

East Texas 177

(30%)

Mid-Con 185

(31%)

Rockies 233

(39%)

Gas 71%

Oil 16%

NGL 13%

Continuing Shift in Production to Liquids

(3%)

+~8%

+~11%

54.1 Bcfe 595 MMcfe/d

Q2’13 Production by Commodity Q2’13 Production by Division

436

425

415

420

425

430

435

440

Q1'13 Q2'13

Natural Gas (Mmcf/d)

14.3 15.5

0

5

10

15

20

Q1'13 Q2'13

Oil (MBbls/d)

11.6 12.9

0

5

10

15

Q1'13 Q2'13

NGL (MBbls/d)

591 595

500

550

600

650

Q1'13 Q2'13

Total (MMcfe/d)

+~1%

Solid Sequential Liquids Growth

4

Drill Bit Focused Capital Program

$758 million

2013 Budget

$628 million

Drilling & Completion

Capital spend focused on the drill bit

Continuing to focus on liquids-rich

drilling projects – Shannon (North Tree),

Ft. Union, Granite Wash, Marmaton,

Bakken and Cotton Valley Sands

Multi-well pad drilling across portfolio

Capital Spend Tracking with Budget

(in millions) 2013 YTD (1)

Drilling and Completion $334 91%

Leasehold Geological & Geophysical 12 3%

Midstream, Corp & Other 24 6%

Total $370 100%

Capitalized Interest 147

Capitalized G&A 16

Total Capital Expenditures $533

East Texas 13%

Mid Continent 40%

Rocky Mountains

47%

Drilling & Completions

83%

Midstream & Other

8%

LG&G 9%

(1) 6ME as of 6/30/2013 5

Rocky Mountain Operations

Samson Rigs

6

North Dakota

Wyoming

Colorado

Diversified Position Across Several Basins with Catalysts for Growth

Utah

Idaho

Stacked oil plays targeting: Shannon,

Sussex, Muddy, and Frontier Q2’13 Production: 4.0 MBoe/d Rig Count: 2

Powder River Basin:

Three Forks and Middle Bakken

development Q2’13 Production: 4.5 MBoe/d Rig Count: 1

Williston Basin:

Horizontal program in the Ft. Union Q2’13 Production: 85 MMcfe/d Rig Count: 2

Green River Basin:

Mature dry gas asset Q2’13 Production: 98 MMcfe/d

San Juan Basin:

Net Acreage: ~1,000,000

YE 2012 Proved Reserves: 779 Bcfe

Q2’13 Average Daily Production: 233 MMcfe/d

Oil 23%; NGL 11%; Gas 66%

Current Rig Count: 5

Rocky Mountains Snapshot:

Powder River Basin

North Tree Field

Hornbuckle Field

Scott Field

Spearhead Ranch Field

Samson Rigs

7

Asset Map by Field

Extensive Acreage Position Anchored by Shannon Development with Exploration Upside

Targeted Zones

LANCE FM.

FOX HILLS SS

MES

AV

ERD

E LEWIS SS

TEAPOT SS.

PARKMAN SS.

SUSSEX SS.

CO

DY

SHA

LE

SHANNON SS.

STEELE SH.

NIOBRARA SH.

"CARLILE SH."

WALL CR. SS.

FRONTIER FM.

MOWRY SH.

SHELL CREEK SH.

MUDDY SS.

THERMOPOLIS SH. *Strat column from USGS

Powder River Basin – North Tree Field Overview Development Map

8

Samson Rigs

Producing Wells

2013-2014 Planned Drilling

2011-2012 Established Repeatability; 2013 Begins Full Scale Development

Rig Count: Currently operating 2 rigs drilling multi-well pads targeting the Shannon interval

North Tree (Shannon) Activity:

Strategically drilled and completed 7 horizontal wells testing and delineating North Tree Field

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

Next Steps – Begin Development:

2H 2013 Plan: Started July 1st. 12 HZ wells from 4 pads using a combination of short and long reach laterals

2014 Plan: 24 HZ wells from 11 pads using a combination of short and long reach laterals

Full Scale Potential North Tree Field – 17,000 net acres, 28 additional locations on 320 acre spacing

Estimated Well Profile (Short/Long):

D&C: $6.5 / $8.2 MM

EUR: 350 / 580 MBOE

IRR: ~20% / ~38% at 6/28 Strip(1)

2014 Development

2013 Development

(1) 6/28 Strip – 5 Years to Flat: Gas $4.26; Oil $85.29

Powder River Basin – Sussex Overview Sussex by Field

9

Samson Rigs

Producing Wells

Rig Count: Currently no active rigs. Two rigs shared between Powder River and Green River due to wildlife stipulations and permit lead time. Two rigs move from Green River back to Powder River to resume Sussex program in January 2014

Summary:

~60,000 net acres

55 HZ producing Sussex wells in Hornbuckle, Spearhead, and Scott Fields

Q2’13 Production: ~2,800 Boe/d

Next Steps – Development Dependent on Permitting:

25 potential locations in 2014

Continuing to delineate in Scott Field

Additional locations dependent on further

drilling results and defining down spacing

potential

Additional Exploration:

Muddy

Frontier

Hornbuckle

Scott

Spearhead Ranch

Duck Creek Federal 14-29 (Sussex completion)

IP 30: 330+ BOPD

Promising Economics in Delineated Fields

Solid Oil-Weighted Position

Bakken – Ambrose Field Overview Ambrose Field Asset Map

Samson Rigs

10

Rig Count: Plan to operate 1 rig through 2014

drilling Middle Bakken and Three Forks

Williston Basin Snapshot:

~69,000 net acres in Divide County

~29,000 Operated

Q2’13 Production – ~4,500 Boe/d

Next Steps:

Expect to drill 33 gross operated wells in

2013 and ~25 gross operated wells in 2014

Continued focus on cost reductions;

Average CWC declined from ~$9.0 MM in

2010 to ~$7.0 MM in 2012

Estimated Well Profile:

Working Interest: ~43%

D&C: $7.0 MM

TVD: ~8,000’; Lateral: 10,000’

EUR: 394 MBOE

IRR: ~15-20% at $85 WTI

AMBROSE FIELD

Non Operated Acreage

Operated Acreage

Continuous Improvement Support Program Economics

Bakken – Performance Benchmarking Performance Over Time

11

Completed Well Cost performance has improved substantially over the last two years driven by a strong focus on operational improvements and efficiency

Performance vs. Peers

Samson ranks in the top quartile in drilling feet per day relative to other operators in the Bakken

Average Completed Well Cost by Quarter(1) Average Feet per Day by Operator*

Top Quartile

36% reduction since Q4 2010

* Benchmarking data sourced from Smith Bits records for Bakken horizontal wells with TD > 17,000’ spud between 1/1/2012 and 3/14/2013 (1) Several of the wells drilled and completed in Q3 / Q4 2012 were shorter laterals which cost approximately $300,000 - $500,000 less than typical 9,500’ laterals

Significant Resource Potential – Delineation Continues

Green River Basin – Ft. Union Overview Asset Map

Sweetwater

12

Producing Middle HZ Well

Producing Lower HZ Well

Summary:

~32,000 net acres

Currently 16 vertical and 4 horizontal

producing Ft Union wells

Q2’13 Production: 47 MMcfe/d

Activity to Date:

Drilled first HZ well during the 2011-2012 drill

window followed by 3 horizontals during the

2012-2013 drill window

First four HZ wells yielding promising results;

drilling costs were higher than expected due to

difficult down hole complications

Average IP Rate for HZ Wells: 16.4

MMCFD & 346 BOPD

Liquids Rich Gas:

WH Btu Factor: 1.150 – 1.230

WH NGL Yield: 4.4 – 5.9 GPM

WH Condensate Yield: 7 – 30 B/MM

Barricade 41-6 S1LH First Sales: 2/2013 Peak IP Rate: 21.5 MMCFD & 387 BOPD Cum Gas: 2,012 MMCF Cum Oil: 30.2 MBO

Barricade 41-6 S1MH First Sales: 2/2013 Peak IP Rate: 24.2 MMCFD & 500 BOPD Cum Gas: 2,657 MMCF Cum Oil: 78.4 MBO

Barricade 21-11N1MH First Sales: 1/2013 Peak IP Rate: 5.3 MMCFD & 211 BOPD Cum Gas: 617 MMCF Cum Oil: 9.5 MBO

Barricade 14-1H First Sales: 1/2012 Peak IP Rate: 14.4 MMCFD & 286 BOPD Cum Gas: 3,244 MMCF Cum Oil: 88.5MBO

Drilling Program Focused on Maximizing Project Potential

Green River Basin – Ft. Union Overview

Sweetwater

13

Existing HZ Wells Lower Target

Middle Target Upper Target

Rig Count: 2 seasonal rigs (August through February drilling window due to wildlife stipulations)

2013 – 2014 Drilling Plan:

Drill and complete 6 HZ wells

Test spacing & delineate to the Northeast (higher liquids content expected)

Test stacked lateral concept

Target lower drilling costs

Unrisked Resource Potential:

574 BCFe based on 75 wells and 1,800’ spacing

Additional Upside Catalysts:

Potential for stacked laterals

Optimize cost through continuous drilling program


D&C: ~$14 MM

EUR: ~1,320 MBOE

IRR: ~28% at 6/28 Strip(1)

Total Pay Interval ~ 900’

Upper

Lower

Middle

2013-2014 Drilling Plan


Upper Granite Wash: Two rigs testing multi-well pad

development to drive down costs and delineate play –

potential for significant drilling inventory

Marmaton: Running two rig program adjacent to

successful industry activity

Mississippi Lime: Completed first four Mississippi Lime

wells; initial results appear encouraging. Continue to

further delineate this play with potential for additional

acreage / scale

Mid-Continent Operations Focus Areas Asset Map

14

Samson Rigs

Legacy Position Continues to Yield New Opportunities

Net Acreage: ~574,000

Proved Reserves: 627 Bcfe

Q2’13 Average Daily Production : 185 MMcfe/d

Oil 17%; NGL 18%; Gas 65%


Anadarko Shelf – Granite Wash Overview Granite Wash Asset Map

Rig Count: Currently operating 2 rigs drilling multi-well pads targeting Granite Wash stacked pay

Acreage: ~63,000 net acres across Hemphill, Wheeler and Roberts Counties

Potential for ~200 locations

Next Steps:

2H 2013 Plan: Test three pads with 2 – 4 stacked laterals each

Hefley 4 Well Pad targeting four different stacked GW zones

Lister 3 Well Pad targeting three different stacked GW zones

Reduce Well Costs: Average single well D&C $7.2 MM; Target $6.5 MM via pad drilling and completion optimization

Inventory Upside: Validating returns on multi well pads in the Granite Wash will provide 50+ potential pad locations


D&C: ~$6.5 MM

EUR: ~600 MBOE

IRR: ~18% at 6/28 Strip(1)

Transition to Pad Drilling Creates Potential for Long-Term Visibility

Samson Rigs

Stacked GW Potential

2013 Planned Drilling

Pounds 2 Well Pad

Lister 3 Well Pad

Hefley 4 Well Pad

Potential Pad Drilling Locations

Texa

s

Okl

ah

om

a

15


Marmaton

Rig Count: Currently operating 2 rigs in Black Kettle; both rigs will remain in area for balance of 2013

Activity Summary: Drilled 4 wells YTD; 12 wells planned for 2013

Key Goals and Next Steps:

Reduce drill days / cost

Test down dip and infill spacing - Success could yield an additional 30+ locations



D&C: $8.8 MM

TVD: 11,300; Lateral 5,000

EUR: 650 MMBOE

IRR: ~20% at 6/28 Nymex strip(1)

Current Industry Activity: 15 wells drilled to date; current area rig count - 2 Samson rigs, 2 Apache rigs and 1 Chesapeake rig

Overview Asset Map – Black Kettle

Opportunistic Program with the Potential to Add Scale

16

ROGER MILLS

Samson Rigs

Key Wells

Planned Drilling

Maxon 2-13H D&C $8.8MM

IP 30: 1,300 BOPD; 6.4 MMCFD wet gas

EUR: ~815 BOE

Leon 3-10H (2 Well Pad)

Maxon 3-13H

(1) 6/28 Strip – 5 Years to Flat: Gas $4.26 ; Oil $85.29

Samson Rigs

East Texas Operations

Liquids-rich and dry gas producing properties in East

Texas and North Louisiana with focus on liquids-rich

gas drilling

Cotton Valley: Liquids-rich horizontal play –

encouraging well results support continued

development

Haynesville/Bossier: No activity currently,

~116,000 net acres HBP provides exposure to

potential for future gas price uplift

Overview Asset Map – E TX / NW LA

Net Acreage: ~380,000

Proved Reserves: 608 Bcfe

Q2’13 Average Daily Production : 177 MMcfe/d

Oil 5%; NGL 10%; Gas 85%


17

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

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

Twomey Heirs #3H (Cotton Valley C Completion)

30 Day IP - 7,280 Mcfd & 454 BOPD

2013 Remaining B Sand Target

Samson Rigs

Werner-Caraway (7 Well Pad)

18

2013 Remaining C Sand Target

Rig Count: Operating 2 rigs in SE Carthage Field; 7 and 2 well pad in progress

Cotton Valley Snapshot:

Acreage: ~31,000 net acres

Primary Targets: CV C & B Sands

Secondary Target: CV Taylor

Q2’13 Production: 78 MMcfe/d

Next Steps:

Continue focusing on SE Carthage liquids rich intervals; 29 locations remaining (as of 7/1)

D&C down from $7 MM to less than $6 MM, best in class $5 MM well in Q1’13

Estimated Well Profile – CV C & B Sands:


D&C: ~$5.8-6.1 MM

3-Stream EUR: 5.1-7.4 Bcfe

IRR of ~30%- ~50% at 6/28 Strip (1) at ~5.5 MM targeted D&C


Continuous Improvement is Driving Strong Results Relative to Peers

Cotton Valley – Drilling Performance Performance Over Time

19

Since Q4’12, HZ Completed Well Cost performance at SE Carthage Field has improved on average by ~$700,000

Performance vs. Peers

Samson’s last 7 wells continue to demonstrate a focus on operational efficiencies

Average Completed Well Cost by Spud Date Average Feet per Day by Operator*

* Benchmarking data sourced from Smith Bits records for CVS horizontal wells in Panola County, TX. Spud between 1/1/2012 and 3/14/2013

0

100

200

300

400

500

600

700

SAMSONLAST 7

Peer 1 SAMSON Peer 2 Peer 3 Peer 4

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$8,000

$9,000

We

ll 1

We

ll 2

We

ll 3

We

ll 4

We

ll 5

We

ll 6

We

ll 7

We

ll 8

We

ll 9

Wel

l 10

Wel

l 11

Wel

l 12

Wel

l 13

Wel

l 14

Wel

l 15

Wel

l 16

$5.8 MM Average

$6.5 MM Average

Financial Strategy

Committed to a Strong and Stable Capitalization Profile

Target long-term leverage below 3.0x

Maintain financial flexibility to execute on near-term capital plan

Focus on maintaining solid liquidity position – ~$1.5 billion as of 8/1/13

Access equity capital to delever with growth focused acquisition

Capital Spending Decisions Driven by Risked Discounted Cash Flow

Target minimum of 20% IRR for capital projects

Project level cash flow generation and sale of non-core assets will fund development programs

Continue to Improve Operating Margins by Deploying Capital to Highest Return Opportunities

Over 90% of the 2013 drilling budget dedicated to oil / liquids-rich projects

Maximize capital to drill bit

Hedging Strategy Focused on De-Risking Price for Substantial Portion of the Forecasted Production

Target 50% to 75% of rolling 18 to 24 month production

Maintain a diversified group of hedge counterparties

Opportunistically hedge in times of dislocation for longer periods

20

$302 $1,478

$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

Debt Maturities and Current Liquidity

Debt Maturity Profile and Liquidity ($MM)

(1) Revolver borrowings and availability as of 8/1/2013 (excludes outstanding letters of credit)

Sufficient liquidity – No near-term maturities

(1)

As of August 1, 2013, we had $302 million borrowed under our RBL which results in revolver availability of $1.48 billion

RBL Capacity: $1.78B

21

Current Hedge Position As of August 16, 2013

Year MMBtu/d Swap Price

2013 333,000 $3.75

2014 309,000 $4.15

2015 92,000 $4.09

2016 86,000 $4.08

2017 40,000 $3.92

Year Bbls/d Swap Price

2013 17,500 $92.81

2014 16,500 $90.63

2015 3,500 $90.91

Year Bbls/d Swap Price

2013 8,250 $35.77

2014 3,500 $34.65

Gas Swaps Oil Swaps NGL Swaps

2013: August - December

Hedging strategy focused on protecting cash flow from expected future production

22

Reserve Summary NSAI SEC Reserve Report – 12/31/2012

PDP Reserves – by Product Total Proved Reserves – by Product PUD Reserves – by Product

2,014 Bcfe 34% Liquids

1,308 Bcfe 21% Liquids

706 Bcfe 59% Liquids

Oil

(MMBbl) NGL

(MMBbl) Gas (Bcf)

Total (Bcfe)

PV-10 ($MM) % Liquids

PDP 24 22 1,021 1,297 $1,874 21%

PDNP 0 0 9 11 15 16%

PUD 44 25 293 706 851 59%

Total 68 47 1,323 2,014 $2,740 34%

Oil 20%

NGLs 14% Gas

66%

Oil 11%

NGLs 10%

Gas 79%

Oil 38%

NGLs 21%

Gas 41%

SEC Realized Pricing at December 31, 2012

Oil $84.72; Gas $2.272; NGLs $38.12

Using current strip pricing, we add over $1.0 billion of incremental value

23

Adjusted EBITDA Reconciliation Three Months Three Months Twelve Months

Ended Ended Ended

March 31, 2013 June 30, 2013 June 30, 2013 (revised)

Net income (loss) $ (58,229) $ 83,044 $ (1,514,074)

Interest expense, net - - $ -

Provision (benefit) for income taxes (32,385) 46,032 $ (797,126)

Depreciation, depletion and amortization (a) 129,063 127,967 $ 618,208

EBITDA $ 38,449 $ 257,043 $ (1,692,992)

Adjustment for unrealized hedging losses (gains) 64,075 (82,012) 109,300

Adjustment for non-cash stock compensation expense (b) 4,961 6,123 37,850

Adjustment for fees paid to co-investors (c) 5,250 5,250 20,500

Adjustment for fees paid for public company compliance 1,709 568 2,841

Loss on sale of other property and equipment 3,005 - 3,005

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

Adjustment for bad debt expense - -

62

Provision to reduce carrying value of oil and gas properties 69,269 11,061 2,242,447

Unusual or non-recurring charges described in credit agreement 2,812 5,764 8,576

Adjusted EBITDA $ 189,530 $ 203,797 $ 778,232

(a) Includes depreciation, depletion and amortization of oil and gas properties and depreciation and amortization of other property and equipment.

(b) Stock compensation expense recognized in earnings, net of capitalization

(c) Quarterly management fee

(d) Total expenses incurred in Q4 related to the restructuring (including the RIF)

24

This presentation contains forward-looking statements, which reflect our expectations 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” 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. These statements are based on, but not limited to, management’s assessment of such factors as the condition of our industry and the competitive environment. These assessments could prove inaccurate. 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, some or all of which are not predictable or within our control. Although the forward-looking statements contained in this presentation reflect our current beliefs based upon information currently available to us and upon assumptions which we believe to be reasonable, actual results may differ materially from expected results. Factors that may cause actual results to differ from expected results include, among others: fluctuations in natural gas and oil prices; uncertainties relating to the drilling of our wells; estimates of our reserves, future net revenues and PV-10; the timing and amount of future production of natural gas and oil; our financial strategy, liquidity and capital required for our development program; changes in the availability and cost of capital; proved and unproved drilling locations and future drilling plans; production rates relating to our natural gas and oil reserves; our ability to capitalize on opportunistic acquisitions of natural gas and oil reserves; write-downs and decline in value of undeveloped acreage if drilling results are unsuccessful; recording of certain non-cash asset write-downs in the future; liability claims as a result of our natural gas and oil operations; actions taken or non-performance by third parties, including other working interest owners, contractors, operators, processors, transporters and customers; competitive conditions in our industry; the use and development of new industry technologies; our ability to recruit and retain qualified personnel necessary to operate our business; our ability to consummate and successfully integrate acquisitions and our ability to realize any cost savings and other synergies from any acquisition; the performance of our information technology systems; general economic and business conditions; our hedging strategy and results; the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; the effects of derivatives reform legislation; elimination of certain natural gas and oil exploration and development federal and state tax deductions and credits; compliance with existing and future FERC regulation; the effects of existing or future litigation; and plans, objectives, expectations and intentions contained in this presentation that are not historical.

Forward Looking Statements

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital and the timing of development expenditures. Reserve engineering is a process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas and oil that are ultimately recovered. Should one or more of the risks or uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this presentation are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. 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.

august 2013 - samson resources€¦ · samson rigs producing wells rig count: currently no active...

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