Focused on building a solid foundation for future growth and value creation

Transcription

1 MAY 2013

2 The Path to Future Growth 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 Focused on building a solid foundation for future growth and value creation 2

3 Company Highlights Significant operational scale in core areas Rockies, Mid-Continent and East Texas Large, Diversified Asset Base Extensive Acreage Inventory Positions Company for Operational Flexibility 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 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 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 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres 3

4 Large, Diverse E&P Portfolio Snapshot Significant Upside Potential in Existing Resource Base Headquarters: Tulsa, OK Total net acres: ~2.74 million (1) Gross Identified Drilling Locations: 4,594 Sept 2012 Avg Daily Production Rockies (oil, liquids & gas plays) Net acreage: ~1,180,000 (1) Targets: Ft. Union, Sussex, Shannon, Frontier, Three Forks, Middle Bakken Mid-Continent (liquids rich gas plays) Net acreage: ~680,000 Targets: Hogshooter, Cottage Grove, Marmaton NGLs Oil 11% 12% Gas 77% 616 Mmcfe/d 12/31/12 Reserves PDNP 1% PUD 36% 2,047 Bcfe PDP 63% Permian (oil plays) Net acreage: ~115,000 (includes ~75,000 net mineral acres) Targets: Horizontal Wolfcamp, Cline Shale East Texas/ N. Louisiana (oil, liquids & gas plays) Net acreage: 450,000 Targets: Cotton Valley, Haynesville (1) Pro forma 2012 Bakken divestiture of 147,000 net acres 4

5 Reserve Summary NSAI SEC Reserve Report 12/31/2012 Oil (MMBbl) NGL (MMBbl) Gas (Bcf) Total (Bcfe) PV-10 ($MM) % Liquids PDP ,021 1,297 $1,874 21% PDNP % PUD % Total ,343 2,047 $2,760 34% PDP Reserves by Product PUD Reserves by Product Total Proved Reserves by Product GAS 79% OIL 11% NGL 10% GAS 42% OIL 37% GAS 66% OIL 20% NGL 14% NGL 21% 1,308 Bcfe 21% Liquids 739 Bcfe 58% Liquids 2,047 Bcfe 34% Liquids 5

6 Reserves Bridge - PV10 ~$1.2 billion of incremental value in current natural gas price environment Total Proved Reserves: 6/30/2012 vs. 12/31/2012 PV10 by Category ($ in millions) $4,500 $4,000 $3,907 $3,954 PUD 31% $3,500 $3,000 $2,500 ($241) ($370) $210 ($636) ($160) $6 $44 $2,760 ~$1.2 billion PDNP 1% PDP 68% $2,000 $1,500 $1,000 PV10 by Division $500 $0 NSAI Production Price Variance Drilling Acquisitions LOE/Prod. Tax Proved Dev. & Divestitures (1) Changes Reserve Adds Proved Undev. Reserves Adds NSAI 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 NYMEX 4/1/2013 Strip MID-CONTINENT 29% EAST TEXAS 20% ROCKY MOUNTAINS 51% $2,760 MM (1) Acquisitions of $79 million; Divestitures of $715 million 6

7 Extensive Drilling Inventory Emerging Oil and Liquids Opportunities Net Acreage by Core Area (000s) Targeted Play Area Commentary Other 420 Rockies 1,183 ETX 450 Mid- Con 684 Shannon Sussex Powder River Powder River Largely de-risked, planning full phase development and infrastructure Combination of development and testing across multiple fields Frontier Powder River Play already being tested/proven Gross Identified Drilling Locations by Core Area Other 124 Rockies 2,312 2,737 Acres (1) ETX 943 Mid-Con 1,215 4,594 Locations 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 Extensive drilling inventory provides visibility to future growth (1) Pro forma 2012 Bakken divestiture of 147,000 net acres 7

8 Returns Focused Development Approach Development Well Economics Ft. Union Bakken Sussex Shannon Upper GW Hogshooter /Cottage Grove Cotton Valley B & C Sands Marmaton EURs (MBOE) 1, , % Liquids 55% 87% 94% 91% 32% 67% 33% 42% D&C Cost ($mm) F&D Cost ($/Boe) $13.5 $7.4 $6.5 $7.4 $6.8 $7.3 $6.5 $9.2 $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% 8

9 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 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 2013 Capital Budget 2013 D&C Budget by Region Facilities 8% Leasehold, Geological & Geophysical 9% ETX 13% Rockies 47% Total Drilling & Completions 83% Mid-Con 40% $758 million $628 million Focused capital program to leverage scale in core areas, transition to greater liquids production profile and accelerate NAV (1) 2013 Plan is to operate four rigs in Green River, but drilling currently limited to August to February period each year. 9

10 Rocky Mountain Operations Overview Asset Map 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 Active Rigs as of April 2013 Net Acreage: ~1,180,000 (1) Proved Reserves: 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 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres 10

11 Powder River Basin Core Position with Multiple Oil Targets Powder River Basin Highlights 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 Asset Map by Field DF Nebraska (Shannon completion) Max IP 1,000+ BOEPD Spearhead Ranch Hornbuckle Muddy HZ Test Program Scott 2013 plan sets the stage for additional development drilling in

12 Powder River Basin Emerging Basin with Multiple Stacked Oil Targets Recent Activity 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.) MESAVERDE Stratigraphic Column LANCE FM. FOX HILLS SS LEWIS SS TEAPOT SS. PARKMAN SS. SUSSEX SS. 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 CODY SHALE Multiple Zones of Pay RKI is drilling horizontal Teapot EOG, Mack, Devon, and RKI drilling horizontal Parkman Samson Sussex development between Spearhead Ranch and Hornbuckle Samson Shannon development in North Tree Chesapeake, SM Energy, Devon, Anadarko, and Helis drilling Horizontal Niobrara Samson Frontier testing near North Tree and Hornbuckle EOG, Anadarko, and Devon drilling horizontal Mowry Samson Muddy testing with 3 horizontal wells in Hornbuckle 12

13 Green River Basin Ft. Union Liquids Rich Gas Development Ft. Union Highlights 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 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 Asset Map Sweetwater 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 Potential for significant production from field 13

14 Bakken Ambrose Developing Three Forks and Middle Bakken 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 Active Rigs as of April 2013 Potential to accelerate production with third rig 14

15 Mid-Continent Operations Overview Asset Map 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 multiwell 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 Active Rigs as of April 2013 Net Acreage: ~684,000 Proved Reserves: 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

16 Anadarko Shelf Team Upper Granite Wash, Hogshooter and Cottage Grove Oil and Liquid Rich Gas Plays Overview Asset Map 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 Active Rigs Samson Rigs 2012 Key Wells 2013 Activity 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 Huff 32-8H Hogshooter IP 24: 5.0 MMcfd, 2,700 BOPD 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 Davis 65-21H (GW Purple) IP24: 11.5 MMcfd, 550 BOPD Balanced approach of acreage optimization, cost initiatives and exploration creates a visible runway 16

17 Horizontal Oil Play Overview Asset Map - Marmaton Activity 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 Apache Galileo 2-4H EUR 128 MBO 3.7 BCF Apache Screaming Eagle 1-16H EUR 160 MBO 2.3 BCF Chesapeake Roark Trust 1-14H IP30: 2,765 BOEPD Active Rigs Samson Rigs 2013 Planned Drilling Apache Skyy 2-33H EUR 209 MBO 5.2 BCF Samson Maxon 2-13H Currently completing Continue optimizing HBP acreage by drilling horizontal oil targets Expand adjacent leasehold to core up position 17

18 East Texas Operations Overview Asset Map E TX / NW LA 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 Net Acreage: ~450,000 Proved Reserves: Bcfe 9/2012 Average Daily Production: 205 MMcfe/d Oil 3%; NGL 8%; Gas 89% Gross Identified Drilling Locations: 943 Current Rig Count: 1 Active Rigs as of April 2013 Adding second rig May

19 East Texas Cotton Valley Liquids-rich Stacked Lateral Development 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 Knight Strong Recent IP 24 : 5.6 MMcfd Liquids Rich Gas and 124 BOPD Crnko Biggs Unit Recently completed 3 well pad. IP 30: 6 MMcfd Liquids Rich Gas & 110 BOPD $5.7MM Avg CWC Drilling Inventory Formation Gross Identified Locations Avg EUR Avg CWC ($mm) Avg WI/NRI CV A Sand Currently Testing Currently Testing $5.9 57%/43% CV B Sand Bcf & 44 MBO $6.5 57%/43% CV C Sand Bcf & 66 MBO $6.4 60%/47% CV Taylor Bcf & 15 MBO $7.7 94%/75% Cost control has led redevelopment of legacy asset 19

20 Focused on Returns Across Portfolio Cost Reduction Initiatives Focused on LOE and Identified D&C Components 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 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

21 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

22 Financial Position Capitalization (1) (as of 9/30/2012) Debt Maturity Profile and Liquidity ($mm) ($ in millions) Capitalization 9/30/2012 % of Cap Reserved Based Credit Facility $ % Second Lien Term Loan 1, % Total Secured Debt $1, % 9.75% Senior Notes $2, % Preferred Stock (3) % Total Debt $3, % Shareholders' Equity 3, % Total Capitalization $7, % $2,250 $1,000 $431 $1,349 $0 $500 $1,000 $1,500 $2,000 $2,500 Revolver - Borrowings Revolver - Availability (2) Second Lien Senior Notes Sufficient liquidity No near-term maturities (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 22

23 Hedge To Protect Cash Flow As of March 28, 2013: Gas Swaps Oil Swaps NGL Swaps Year MMBtu/day Swap Price % of Forecast ,000 $ % ,000 $ ,000 $ ,000 $ ,000 $3.92 Year BOPD Swap Price % of Forecast ,425 $ % ,500 $ ,500 $91.32 Year Bbls/day Swap Price % of Forecast ,485 $ % Hedged ~83% of forecasted 2013 volumes 23

24 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

25 Forward Looking Statements 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.

26 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.