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MAY 2013
2012 2013 2014+
The Path to Future Growth
Focused on building a solid foundation for future growth and value creation
Enhanced rigor applied to capital allocation – return based approach
Cost control initiatives
Improved liquidity with Term Loan
Initiated Enterprise Resource Planning (SAP)
Divested non-core assets
New leadership
Operational excellence
Focusing on core areas
Testing new plays in core areas
Divesting non-core assets
Monitoring M&A market for acquisition opportunities
Focus on returns, growth and portfolio optimization
Transition new play testing to development
Achieve balanced commodity mix
Delever balance sheet and maintain significant financial flexibility
2
Extensive Acreage Inventory Positions
Company for Operational
Flexibility
Focus on Cash Returns
Over 90% of capex focused on drilling oil / liquids-weighted drilling projects
Maintaining ~ 50% liquids target by 2016
Implementing company wide initiatives to enhance well economics through lower cost model
Large, Diversified Asset Base
Significant operational scale in core areas – Rockies, Mid-Continent and East Texas
Extensive current drilling inventory of 4,594 identified locations provides visibility to future growth
opportunities ~82% of which are oil and liquids rich – over 1,750 additional locations in a higher natural gas
price environment
Diversified production across multiple regions – ownership interests in 7,640 gross wells (3,380 net wells)
Over 2.7 million(1) net acres concentrated in our three core areas with ~60% HBP
Diversity of the asset base and significant HBP position in several of our core areas provides flexibility
to focus on highest rate of return projects
Operate 67% of net production which allows more effective management of timing and costs
Company Highlights
Experienced Management and
Technical Team
Senior management team has extensive expertise in the oil and natural gas industry – senior
management has on average 25+ years of industry experience
Technical professionals have an average of 20+ years industry experience
Solid Financial Flexibility
As of 4/1/2013, over $1.3 billion of liquidity with access to equity for growth focused initiatives
Proactively hedge to protect cash flows and capital program
3 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres
Significant Upside Potential in Existing Resource Base Snapshot
Headquarters: Tulsa, OK
Total net acres: ~2.74 million (1)
Gross Identified Drilling Locations: 4,594
Sept 2012 Avg Daily Production
12/31/12 Reserves
616 Mmcfe/d
Large, Diverse E&P Portfolio
(1) Pro forma 2012 Bakken divestiture of 147,000 net acres
PDNP 1%
PDP 63%
PUD 36%
2,047 Bcfe
Rockies (oil, liquids & gas plays) Net acreage: ~1,180,000(1)
Targets: Ft. Union, Sussex, Shannon, Frontier, Three Forks, Middle Bakken
Permian (oil plays) Net acreage: ~115,000 (includes ~75,000 net mineral acres) Targets: Horizontal Wolfcamp, Cline Shale
Mid-Continent (liquids rich gas plays) Net acreage: ~680,000 Targets: Hogshooter, Cottage Grove, Marmaton
East Texas/ N. Louisiana (oil, liquids & gas plays) Net acreage: 450,000 Targets: Cotton Valley, Haynesville
Gas 77%
Oil 12%
NGLs 11%
4
OIL 37%
NGL 21%
GAS 42%
5
Reserve Summary
NSAI SEC Reserve Report – 12/31/2012
Oil
(MMBbl) NGL
(MMBbl) Gas (Bcf)
Total (Bcfe)
PV-10 ($MM) % Liquids
PDP 24 22 1,021 1,297 $1,874 21% PDNP 0 0 9 11 15 16% PUD 45 26 313 739 871 58% Total 69 48 1,343 2,047 $2,760 34%
OIL 20%
NGL 14% GAS 66%
PDP Reserves – by Product Total Proved Reserves – by Product PUD Reserves – by Product
2,047 Bcfe 34% Liquids
OIL 11%
NGL 10%
GAS 79%
1,308 Bcfe 21% Liquids
739 Bcfe 58% Liquids
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
$3,500
$4,000
$4,500
NSAI 6.30.12 Production Price Variance
Drilling Acquisitions & Divestitures
(1)
LOE/Prod. Tax Changes
Proved Dev. Reserve Adds
Proved Undev.
Reserves Adds
NSAI 12.31.12 NYMEX 4/1/2013
Strip
6
Reserves Bridge - PV10 ~$1.2 billion of incremental value in current natural gas price environment
Total Proved Reserves: 6/30/2012 vs. 12/31/2012
($ in millions)
PV10 by Category
PV10 by Division
PDP 68%
PDNP 1%
PUD 31%
EAST TEXAS 20%
$2,760 MM
(1) Acquisitions of $79 million; Divestitures of $715 million
MID-CONTINENT 29%
ROCKY MOUNTAINS
51% SEC Realized Pricing: Oil: $84.72 at Dec. 31 compared to $86.23 at June 30
Gas: $2.272 at Dec. 31 compared to $2.658 at June 30
NGLs: $38.12 at Dec. 31 compared to $44.70 at June 30
($241)
$3,907
($370)
$210
$6 $44 $2,760 ($636)
($160)
$3,954
~$1.2 billion
Extensive Drilling Inventory
Net Acreage by Core Area (000s)
Gross Identified Drilling Locations by Core Area
Extensive drilling inventory provides visibility to future growth
ETX 943
Mid-Con 1,215
Rockies 2,312
Other 124
4,594 Locations
Emerging Oil and Liquids Opportunities
ETX 450
Mid-Con 684
Rockies 1,183
Other 420
2,737 Acres (1)
7 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres
Targeted Play Area Commentary
Shannon Powder River Largely de-risked, planning full phase
development and infrastructure
Sussex Powder River Combination of development and testing across
multiple fields
Frontier Powder River Play already being tested/proven
Muddy Powder River Initial test wells encouraging
Middle Bakken Williston Initial stages of development
Marmaton Mid-Continent Industry results validate play
Granite Wash Mid-Continent Liquids rich gas
Cotton Valley Sands East Texas Liquids stream supports horizontal
development
Returns Focused Development Approach
Ft. Union Bakken Sussex Shannon Upper GW Hogshooter
/Cottage Grove
Cotton Valley B & C Sands
Marmaton
EURs (MBOE)
1,357 425 346 353 735 357 1,218 720
% Liquids 55% 87% 94% 91% 32% 67% 33% 42%
D&C Cost ($mm)
$13.5 $7.4 $6.5 $7.4 $6.8 $7.3 $6.5 $9.2
F&D Cost ($/Boe)
$9.95 $17.38 $18.79 $20.95 $9.25 $20.47 $5.34 $12.78
IRRs ~30% >20% >20% >20% >20% >20% ~33% >20%
Development Well Economics
8
Total Drilling &
Completions 83%
Leasehold, Geological & Geophysical
9%
Facilities 8%
Liquids-Focused Capital Budget Allocating over 90% of 2013 capital budget to oil / liquids-focused drilling projects
Plan to drill ~150 gross operated wells in 2013 Budget for 10-13 rigs operating in our core areas – Rocky Mountains, Mid-Con and East Texas
Focus areas include the Powder River Basin (2 rigs), Green River (4 rigs)(1), Bakken (2 rigs), Mid-Con (4 rigs) and East Texas (1 rig)
Capital program driven by unlevered cash flows from business – funded from operating cash flows, allowing us to maintain financial flexibility while growing existing reserves and production
ETX 13%
Mid-Con 40%
Rockies 47%
2013 Capital Budget 2013 D&C Budget by Region
Focused capital program to leverage scale in core areas, transition to greater liquids production profile and accelerate NAV
9
$758 million $628 million
(1) 2013 Plan is to operate four rigs in Green River, but drilling currently limited to August to February period each year.
Overview
Focus on oil and liquids rich properties in four major producing basins:
Powder River Basin: Stacked oil plays targeting the oil zones: Shannon, Sussex, Muddy, and Frontier
Green River Basin: Horizontal program in the Ft. Union
Williston Basin: Three Forks and Middle Bakken development
San Juan Basin: Mature dry gas asset
Rocky Mountain Operations Asset Map
Net Acreage: ~1,180,000(1)
Proved Reserves: 781.3 Bcfe
9/2012 Average Daily Production: 210 MMcfe/d
Oil 22%; NGL 6%; Gas 72%
Gross Identified Drilling Locations: 2,312
Current Rig Count: 4
10 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres
Active Rigs as of April 2013
2013 plan sets the stage for additional development drilling in 2014
Currently, Samson has 275,000 acres across the region and plans to operate two horizontal rigs this year
Shannon well results are encouraging
Plan to drill ~10 horizontal Shannon wells in 2013
Continue infill development of our Sussex program and expand Sussex core area
Plan to drill 16 horizontal Sussex wells in 2013
Mature Muddy delineation with 3 horizontal wells
Recent industry horizontal Frontier wells have EURs of 600+ MBOE – supports testing
North Tree
Hornbuckle
Scott
Spearhead Ranch
Powder River Basin
Powder River Basin Highlights Asset Map by Field
Core Position with Multiple Oil Targets
DF Nebraska (Shannon completion) Max IP 1,000+ BOEPD
Muddy HZ Test Program
11
Chesapeake, SM Energy, Devon, Anadarko, and Helis drilling Horizontal Niobrara
EOG, Mack, Devon, and RKI drilling horizontal Parkman
EOG, Anadarko, and Devon drilling horizontal Mowry
RKI is drilling horizontal Teapot
Samson Sussex development between Spearhead Ranch and Hornbuckle
Samson Shannon development in North Tree
Samson Frontier testing near North Tree and Hornbuckle
Samson Muddy testing with 3 horizontal wells in Hornbuckle
Recent Activity Multiple Zones of Pay
Sussex:
Activity in the Sussex has increased in recent months with Bill Barrett, Chesapeake and QEP permitting and drilling wells in vicinity of Samson’s acreage
Consistent geology across core play area indicates possibility for consistent results
Shannon:
Activity in the Shannon has increased in recent months with Bill Barrett, Anadarko, and Devon permitting and drilling wells near Samson’s acreage
Recent strong results have expanded the development area of North Tree field
Frontier:
Recent horizontal Frontier wells in the area have EURs of 600+ MBOE
Recent results from Frontier wells near Hornbuckle have opened up additional inventory of horizontal locations
Current activity by other operators helping to further confirm potential (Devon, Helis, Bill Barrett, SM, etc.)
Powder River Basin Emerging Basin with Multiple Stacked Oil Targets
Stratigraphic Column
LANCE FM. FOX HILLS SS
MES
AVER
DE LEWIS SS
TEAPOT SS.
PARKMAN SS.
SUSSEX SS.
COD
Y SH
ALE
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
12
Total acreage position of 37,500 acres between Barricade and Endurance units
Identified 93 gross horizontal locations, with potential for 2 or 3 stacked laterals per location
4 horizontals wells currently producing
Plan to operate four rigs during the Aug 2013 - Feb 2014 drilling window
Plan to drill 9 horizontal wells
Drilling window limited by wildlife stipulations which restricts year round operations
Pursuing year round drilling options
Potential for significant production from field
Green River Basin – Ft. Union
Ft. Union Highlights
Liquids Rich Gas Development
Asset Map
Horizontal Wells Drilled
Barricade 14-1H First Sales 1/2012 IP Rate 14.4 MMcfd & 286 BOPD Cum Gas 2,912 MMcf Cum Oil 80 MBO
13
Sweetwater
Potential to accelerate production with third rig
Bakken – Ambrose
Bakken Highlights Asset Map: Ambrose Focus Area
Ambrose Area: ~ 75,000 acres
Currently operating two rigs
Plan to drill ~40 gross operated wells in 2013
Continued focus on cost savings through pad drilling, cycle time initiatives and optimal frac designs
Industry leading cycle times
Initial phase of the Oneok Gas Gathering System is in service
Over 730 gross identified drilling locations across our entire Bakken position
Developing Three Forks and Middle Bakken
14
Active Rigs as of April 2013
4,153 gross producing wells from 25+ established productive intervals across the Anadarko, Arkoma and Ardmore basins
Current focus areas include:
Hogshooter / Cottage Grove Wash: Samson has drilled and completed several Hogshooter and Cottage Grove Wash wells with results exceeding 50% IRR’s on a program basis. Currently operating two rigs in the play
Upper Granite Wash: Drive efficiencies through multi-well pad development to increase IRR’s
Marmaton: Currently drilling several Marmaton wells adjacent to industry activity
Mississippi Lime: Completed first two Mississippi Lime wells which exceeded expectations. Samson will further delineate this play and expects future activity in this play along with other oil plays across the Mid- Continent Division
Mid-Continent Operations
Overview Asset Map
Net Acreage: ~684,000
Proved Reserves: 657.7 Bcfe
9/2012 Average Daily Production: 199 MMcfe/d
Oil 12%; NGL 19%; Gas 69%
Gross Identified Drilling Locations: 1,215
Current Rig Count: 4
15
Active Rigs as of April 2013
Davis 65-21H (GW Purple) IP24: 11.5 MMcfd, 550 BOPD
16
Anadarko Shelf Team
Huff 32-8H Hogshooter IP 24: 5.0 MMcfd, 2,700 BOPD
2012 Key Wells
Approximately 70,000 net acres in Roberts, Hemphill, and Wheeler Counties
90% of the acreage HPB
Continuous 2 rig drilling program with plans for additional rigs starting in 2014
Upper Granite Wash, Hogshooter and Cottage Grove Oil and Liquid Rich Gas Plays
Drill stacked laterals from multi-well pads in Upper Granite Wash Pay of the Buffalo Wallow Field
3 to 4 wells per pad Reduce well cost ~ 10% Expand play to other Granite Wash
Expand Hogshooter / Cottage Grove play to newly acquired acreage closer to the mountain front
Test and delineate a Pennsylvanian Douglas Horizontal Play on existing HBP Acreage
Samson Rigs
2013 Activity
Overview
Active Rigs
Balanced approach of acreage optimization, cost initiatives and exploration creates a visible runway
Davis 64 Cottage Grove and Hogshooter 64-5H IP 24: 7.0 MMcfd + 2,300 BOPD
64-9H IP 24: 2.6 MMcfd + 1,900 BOPD 64-10H IP 24: 2.7 MMcfd + 2,000 BOPD
Asset Map
17
Horizontal Oil Play
Operate 2 rigs through 2013 drilling Marmaton horizontals
Legacy acreage position provides broad exposure to stacked pay across the region
Identified numerous horizontal oil drilling opportunities including: Tonkawa, Cleveland, Marmaton and Mississippian target horizons
Recent drilling results include two horizontal Cleveland wells that had an average 30-day IP of 1,250 boepd Samson Rigs
Active Rigs
Chesapeake Roark Trust 1-14H IP30: 2,765 BOEPD
Samson Maxon 2-13H Currently completing
Apache Skyy 2-33H EUR 209 MBO 5.2 BCF
Apache Galileo 2-4H EUR 128 MBO 3.7 BCF
Apache Screaming Eagle 1-16H EUR 160 MBO 2.3 BCF
2013 Planned Drilling
Overview Asset Map - Marmaton Activity
Continue optimizing HBP acreage by drilling horizontal oil targets – Expand adjacent leasehold to core up position
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, 75,000 net acres high graded and HBP
~750 identified locations
Overview Asset Map – E TX / NW LA
Net Acreage: ~450,000
Proved Reserves: 596.6 Bcfe
9/2012 Average Daily Production: 205 MMcfe/d
Oil 3%; NGL 8%; Gas 89%
Gross Identified Drilling Locations: 943
Current Rig Count: 1
18
Active Rigs as of April 2013 Adding second rig May 2013
Formation Gross Identified
Locations Avg EUR
Avg CWC ($mm)
Avg WI/NRI
CV A Sand Currently Testing Currently Testing $5.9 57%/43%
CV B Sand 21 5.9 Bcf & 44 MBO $6.5 57%/43%
CV C Sand 20 5.4 Bcf & 66 MBO $6.4 60%/47%
CV Taylor 71 4.2 Bcf & 15 MBO $7.7 94%/75%
East Texas – Cotton Valley Liquids-rich Stacked Lateral Development
Crnko Biggs Unit Recently completed 3 well pad. IP
30: 6 MMcfd Liquids Rich Gas & 110 BOPD
$5.7MM Avg CWC
Cotton Valley Highlights
Plan to operate one rig throughout 2013, adding a second rig in May 2013
Plan to drill ~ 20 CV Horizontal wells in 2013
Primary targets include B and C Sands
Testing A Sand potential
Focused on cost efficiencies
Multi-well pads; currently drilling a 4-well pad (exploring potential to expand to 6-well pads)
Zipper Fracs
Drilling stacked laterals
Bi-fuel rigs capable of using natural gas and diesel
Currently 24 Horizontal CV wells producing
Apply Southeast Carthage Field successes to CV Taylor program to drive down costs and improve economics
Focus Area - Southeast Carthage Field
Drilling Inventory
Knight Strong Recent IP 24 :
5.6 MMcfd Liquids Rich Gas and 124 BOPD
19
Cost control has led redevelopment of legacy asset
Focused on Returns Across Portfolio
Lease Operating Expense
Initiatives
Field driven, comprehensive
reviews of controllable spend areas
Over 90 identified savings opportunities
Examples:
1. SWD Costs
2. Compression
3. Chemicals
Early Results:
SWD Hauling down 10%-20%
Chemical Cost Reductions:
40% NLA & 26% in MidCon
Cost Reduction Initiatives Focused on LOE and Identified D&C Components
Supply Chain Management
Initiatives
1. Contract management of key drilling and completion products and services such as:
- Stimulation
- Cementing
- Mud & Services
2. Increase visibility across all spend
3. Expand and audit price agreements
4. Standardize equipment
5. Contractor performance management
Estimate $20MM-$40MM
in annual savings
Driving costs down in 2013 through excellence in execution and process improvements
20
Financial Strategy
Committed to a Strong and Stable Capitalization Profile
Target long-term leverage of 3.5x or below while maintaining financial flexibility to execute on capital plan objectives
Focus on maintaining solid liquidity position – ~$1.3 billion as of 4/1/13
No near-term maturities – helps mitigate liquidity risk
Capital Spending Decisions Driven by Risked Discounted Cash Flow
Minimum of 20% IRR required for all capital projects
Project level cash flow generation and sale of non-core assets will significantly fund development programs
Continue to Improve Operating Margins by Deploying Capital to Highest Return Opportunities
Over 90% of the 2013 drilling budget dedicated to oil / liquids-rich projects
Actively manage acreage positions
Hedging Strategy Focused on De-Risking Price for Substantial Portion of the Forecasted Production
Target 50% to 75% of rolling 18 to 24 month production
Maintain a diversified group of hedge counterparties
Opportunistically hedge in times of dislocation for longer periods
21
Financial Position
Capitalization (1) (as of 9/30/2012)
Debt Maturity Profile and Liquidity ($mm)
(1) As adjusted for 2012 Bakken Divestiture (2) Revolver borrowings and availability as of 4/1/2013 (inclusive of outstanding letters of credit) (3) Book Value of cumulative preferred stock with an aggregate liquidation preference of $182.8 million
Sufficient liquidity – No near-term maturities
22
(2)
$431 $1,349
$1,000
$2,250
$0 $500 $1,000 $1,500 $2,000 $2,500
2016
2017
2018
2019
2020
Revolver - Borrowings Revolver - Availability
Second Lien Senior Notes
(3)
($ in millions)
Capitalization 9/30/2012 % of Cap
Reserved Based Credit Facility $365 4.9%
Second Lien Term Loan 1,000 13.4%
Total Secured Debt $1,365 18.3%
9.75% Senior Notes $2,250 30.1%
Preferred Stock 171 2.3%
Total Debt $3,786 50.7%
Shareholders' Equity 3,683 49.3%
Total Capitalization $7,470 100.0%
Hedge To Protect Cash Flow As of March 28, 2013:
Hedged ~83% of forecasted 2013 volumes
Year MMBtu/day Swap Price
% of Forecast
2013 341,000 $3.76 82%
2014 309,000 $4.15
2015 92,000 $4.09
2016 86,000 $4.08
2017 40,000 $3.92
Year BOPD Swap Price % of
Forecast
2013 16,425 $92.45 99%
2014 16,500 $90.80
2015 3,500 $91.32
Year Bbls/day Swap Price % of
Forecast
2013 7,485 $36.05 60%
Gas Swaps Oil Swaps NGL Swaps
23
Key Takeaways
Execution across the Company is the focus for 2013 and beyond
Transition the production profile and asset base to a more balanced mix of oil / liquids and natural gas
Realize value of Rockies assets by delineating acreage position, demonstrating repeatable EURs, and driving down costs
Enhance returns from Mid-Con and East Texas programs through operational improvements
Optimize present value of assets through active portfolio management
Commitment to reducing leverage and maintaining / enhancing financial flexibility
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.