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

Transcription

1 July 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 current drilling inventory of over 4,500 identified locations provides visibility to future growth opportunities ~82% of which are oil and liquids rich Diversified production across multiple regions ownership interests in 7,640 gross wells (3,380 net wells) Extensive Acreage Inventory Positions Company for Operational Flexibility Over 2.6 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 6/30/2013, over $1.42 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 and 2013 Permian divestitures expected to close in aggregate by Q

4 Large Asset Base Snapshot Significant Upside Potential in Existing Resource Base Headquarters: Tulsa, OK Total net acres: ~2.63 million (1) 2013 Q1 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, Granite Wash, Cottage Grove, Marmaton Gas 74% Oil 14% NGL 12% 591 Mmcfe/d 12/31/12 Reserves PUD 35% PDNP 1% 2,014 Bcfe PDP 64% Active Rigs as of June 2013 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 and 2013 Permian divestitures expected to close in aggregate by Q

5 Q Summary Review (1) Net of non-cash equity compensation Key Metrics Q compared to Q Three Months Ended March 31, Change Revenue ($ in millions) Gas and NGL $150 $138 9% Oil (10%) Derivatives (50) 20 NM Total Revenue $213 $284 (25%) Operating Expense ($ per Mcfe) LOE $0.94 $0.90 4% Production/Ad Val Tax $0.35 $0.47 (26%) DD&A $2.43 $2.59 (6%) G&A (1) $0.50 $ % Pricing Before the effects of hedges Gas ($ per Mcf) $3.46 $ % Oil ($ per barrel) $82.23 $98.00 (16%) Combined Production ($ per Mcfe) $5.09 $4.82 6% After the effects of hedges Gas ($ per Mcf) $3.83 $3.78 1% Oil ($ per barrel) $80.67 $87.16 (7%) Combined Production ($ per Mcfe) $5.37 $5.29 2% Capital Expenditures Drilling and Completion $190 $368 (48%) Leasehold Geological & Geophysical 5 38 (87%) Midstream, Corp & Other (29%) Total $208 $423 (50%) Capitalized Interest % Total Capital Expenditures $335 $463 (23%) Q1 13 Production by Product Gas 74% Oil 14% 53.2 Bcfe NGL 12% Q1 13 Avg Daily Production by Division Rockies 216 (37%) Mid- Con 180 (30%) East Texas 195 (33%) 591 Mmcfe/d 5

6 Returns Focused Development Approach Expected 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% 6

7 Liquids-Focused Capital Program Region 2013 Budget ($ in MM) Basin/Field Targeted Plays / Formations Current Rig Count Rockies $ Powder River Basin Shannon 2 Green River Basin Ft. Union 2 (1) Bakken Middle Bakken, Three Forks 2 Mid-Con $ Anadarko Basin Hogshooter, Marmaton 2 Granite Wash 2 East Texas $75-80 SE Carthage Cotton Valley Sands ( C and B ) 2 Total $ Capital Budget Q Capital Spend vs Budget Facilities Leasehold, 8% Geological & Geophysical 9% Total Drilling & Completions 83% (in millions) 2013 Capital Budget % of Budget Actual Q1' 13 % of Q1'13 Actuals Drilling and Completion $628 83% $190 91% Leasehold, geological and geophysical 70 9% 5 2% Midstream, corporate and other 60 8% 13 6% Total $758 $208 $758 million (1) Drilling window limited by wildlife stipulations, plan to operate 2 rigs during the Aug 2013 Feb 2014 drilling window 7

8 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 June 2013 Net Acreage: ~1,180,000 (1) Proved Reserves: 779 Bcfe Q1 13 Average Daily Production: 216 MMcfe/d Oil 23%; NGL 8%; Gas 69% Current Rig Count: 4 (1) Pro forma 2012 Bakken divestiture of 147,000 net acres 8

9 Powder River Basin Core Position with Multiple Oil Targets Powder River Basin Highlights / Plans Asset Map by Field Currently, Samson has 275,000 acres across the region and plans to operate two horizontal rigs this year DF Nebraska H (Shannon completion) Max IP: BOPD Continue development of Sussex at Hornbuckle Begin full scale development of North Tree Monitor industry activity in horizontal Frontier and Muddy programs for future exploration potential North Tree Spearhead Ranch TCR Kentucky Fee bh (Shannon completion) Duck Creek Federal (Sussex completion) Hornbuckle Scott Active Rigs as of June 2013 Key Wells 2013 plan sets the stage for additional development drilling in

10 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 two rigs during the Aug Feb 2014 drilling window Plan to drill 6 horizontal wells Drilling window limited by wildlife stipulations which restricts year round operations Pursuing year round drilling options Horizontal Wells Drilled Asset Map Sweetwater 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 10

11 Bakken Ambrose Field 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 Border Farms TFH (Three Forks Completion) 30 Day IP 575+ BOPD Thomte TFH (Middle Bakken Completion) 30 Day IP 725+ BOPD Nomad TFH (Three Forks Completion) 30 Day IP 450+ BOPD Initial phase of the Oneok Gas Gathering System is in service Active Rigs as of June 2013 Key Wells Cost initiatives driving program economics 11

12 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: Testing multi-well pad development to drive down costs and delineate play potential Marmaton: Running two rig program adjacent to successful industry activity. Mississippi Lime: Completed first three 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 June 2013 Net Acreage: ~684,000 Proved Reserves: Bcfe Q1 13 Average Daily Production: 180 MMcfe/d Oil 14%; NGL 19%; Gas 67% Current Rig Count: 4 12

13 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 Active Rigs Samson Rigs 2012 Key Wells Continuous 2 rig drilling program with plans for additional rigs starting in Activity Huff 32-8H (Hogshooter) IP 24: 5.0 MMcfd, 2,700 BOPD 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 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 13

14 Horizontal Oil Play Overview Asset Map - Marmaton Activity Legacy acreage position provides broad exposure to stacked pay across the region Operate 2 rigs through 2013, drilling 8 Marmaton horizontals with ~20 additional locations Drilled 3 Mississippi Lime wells in 2013 with encouraging results and ~20 unrisked future locations. 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 14

15 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 providing exposure to improving future gas markets Net Acreage: ~450,000 Proved Reserves: 608 Bcfe Q1 13 Average Daily Production : 195 MMcfe/d Oil 5%; NGL 10%; Gas 85% Current Rig Count: 2 Active Rigs as of June

16 East Texas Cotton Valley Liquids-rich Stacked Lateral Development Cotton Valley Highlights Focus Area - Southeast Carthage Field Added a second rig in May 2013 Plan to drill ~ 20 CV Horizontal wells in 2013 Werner-Caraway SL #7H (7 Well Pad) Primary targets include B and C Sands Focused on cost efficiencies Multi-well pads; currently drilling a 7-well pad Zipper Fracs Twomey Heirs #3H (Cotton Valley C Completion) 30 Day IP - 7,280 Mcfd & 454 BOPD Drilling stacked laterals Bi-fuel rigs capable of using natural gas and diesel Currently 24 Horizontal CV wells producing Key Wells Samson Rigs Cost control has led redevelopment of legacy asset 16

17 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 ,323 2,014 $2,740 34% 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 PDP Reserves by Product PUD Reserves by Product Total Proved Reserves by Product Gas 79% Oil 11% NGLs 10% Gas 41% NGLs 21% Oil 38% Gas 66% Oil 20% NGLs 14% 1,308 Bcfe 21% Liquids 706 Bcfe 59% Liquids 2,014 Bcfe 34% Liquids 17

18 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 ~$1.42 billion as of 6/30/13 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 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 18

19 Debt Maturities and Current Liquidity Debt Maturity Profile and Liquidity ($MM) 2020 $2, $1, $360 $1,420 RBL Capacity: $1.78B $0 $500 $1,000 $1,500 $2,000 $2,500 Revolver - Borrowings Revolver - Availability(1) Second Lien Senior Notes As of June 30, 2013, we had $360 million borrowed under our RBL which results in revolver availability of $1.42 billion Sufficient liquidity No near-term maturities (1) Revolver borrowings and availability as of 6/30/2013 (excludes outstanding letters of credit) 19

20 Current Hedge Position As of July 1, 2013 Gas Swaps Oil Swaps NGL Swaps Year MMBtu/d Swap Price ,000 $ ,000 $ ,000 $ ,000 $ ,000 $3.92 Year Bbls/d Swap Price ,500 $ ,500 $ ,500 $90.91 Year Bbls/d Swap Price ,150 $35.76 Hedged ~83% of forecasted July December 2013 total hydrocarbon volumes 2013: July - December 20

21 Adjusted EBITDA Reconciliation Three Months Three Months Twelve Months Ended Ended Ended March 31, 2013 March 31, 2012 March 31, 2013 Net income/(loss) $ (58,229) $ (76,968) $ (1,511,290) Interest expense, net Provision for income taxes (32,385) (42,177) (796,126) Depreciation, depletion and amortization (a) 129, , ,232 EBITDA $ 38,449 $ 36,307 $ (1,651,184) Adjustment for unrealized hedging losses 64,020 5,100 64,624 Adjustment for non-cash stock compensation expense (b) 4,961-40,567 Adjustment for fees paid to co-investors (c) 5,250 5,000 20,250 Adjustment for fees paid for SOX compliance Adjustment for restructuring expenses (d) ,643 Adjustment for bad debt expense Adjustment for loss on early extinguishment of debt - 44,815 - Provision to reduce carrying value of oil and gas properties 69,269 91,410 2,231,386 Adjusted EBITDA $ 182,143 $ 182,632 $ 753,106 (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) Management fee paid quarterly (d) Total expenses incurred in Q4 related to the restructuring (including the RIF) 21

22 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.

23 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.