Focusing on Liquids-rich Targets in Existing Resource Base

Transcription

1 November 2013

2 Company Overview Company Snapshot Focusing on Liquids-rich Targets in Existing Resource Base Proved Reserves (12/31/12): 2.0 Tcfe Q Production: 595 MMcfe/d (29% Liquids) Operated Rigs: 11 Total Net Acres: ~2.2 million Q2 13 Production by Area (MMcfe/d) Rockies Targets: Shannon, Sussex, Frontier, Three Forks, Middle Bakken, Ft. Union, Muddy Legacy Position: San Juan Mid-Continent & East Texas Targets: Marmaton, Granite Wash, Hogshooter / Cottage Grove Wash, Cotton Valley Sands and Haynesville / Bossier Rockies 233 East Texas 177 Mid-Con 185 As of 12/31/12 Reserves by Category PUD 35% PDNP 1% PDP 64% Samson Rigs 2

3 Committed Leadership with Investor Support Industry Experience Public Company Experience Randy Limbacher - Chief Executive Officer and Director Richard Fraley - Executive Vice President and Chief Operating Officer Phil Cook - Executive Vice President and Chief Financial Officer Louis Jones - Executive Vice President of Business Development, New Ventures and Portfolio Management Andrew Kidd - Senior Vice President and General Counsel Committed Equity Investors with Significant Industry Experience / Investment Exposure 3

4 Corporate Strategy Optimize Capital Program Maximize dollars at the drill bit Focus on prospects with higher liquids content (returns focused drilling program) Reduce costs and improve efficiencies in the field Future Drill Bit Inventory Delineate the liquids-rich Ft. Union and Granite Wash positions Bolt-on to existing core positions Actively monitor M&A market for potential acquisitions that provide visibility and inventory Protect the Balance Sheet in Short Term Lower exploration risk Well hedged for the next months Incremental non-core assets sales Estimate of $300 million for 2013 Long Term Opportunities to Strengthen Balance Sheet Equity contribution to fund growth from acquisitions or acceleration of delineated inventory Position portfolio for public market access 4

5 Delivering on Liquids Growth MBbl/d 30 Liquids Production by Quarter % Liquids 35% 26% 29% 30% 20 22% 25% 19% % % 10% 5% Q1'12* Q2'12* Q1'13 Q2'13 0% NGL Oil % Liquids * Excludes production from Bakken divestiture 5

6 D&C Costs per Well ($MM) Reducing Drilling & Completion Costs $7.0 Down ~8% Pad Drilling Completion Service Provider Reductions $6.6 $6.5 $6.0 $6.1 $6.0 Down ~8% $5.5 $5.5 $ YTD YTD Bakken - Ambrose Field Cotton Valley - SE Carthage Driving Down Costs Across the Portfolio Note: 2013 YTD represents wells spud through May for Bakken and April for Cotton Valley 6

7 Improving Relative Cost Structure Commitment to Continual Improvement Lease Operating Expense Flat despite shift to higher cost liquids focused drilling Cash G&A Reduced compensation expense ($ per Mcfe) Lease Operating Expense $0.94 $0.93 ($ MM) Cash G&A (1) $70 $63 $60 $50 $54 $0.92 $0.91 $0.92 $0.92 $40 $30 $20 $10 $0.90 1H'12 1H'13 $0 1H'12 1H'13 (1) Income Statement G&A (excluding non-cash compensation & management fee) 7

8 Rocky Mountain Operations Rocky Mountains Snapshot: 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 North Dakota Powder River Basin: Williston Basin: Three Forks and Middle Bakken development Q2 13 Production: 4.5 MBoe/d Rig Count: 1 Idaho Wyoming Stacked oil plays targeting: Shannon, Sussex, Muddy, and Frontier Q2 13 Production: 4.0 MBoe/d Rig Count: 2 Green River Basin: Utah Colorado Horizontal program in the Ft. Union Q2 13 Production: 85 MMcfe/d Rig Count: 2 San Juan Basin: Samson Rigs Mature dry gas asset Q2 13 Production: 98 MMcfe/d Diversified Position Across Several Basins with Catalysts for Growth 8

9 Green River Basin Ft. Union Overview Rig Count: Currently operating 2 rigs Acreage: 39,900 gross acres / 32,000 net acres Q2 13 Production: 47 MMcfe/d, up 95% from Q1 13 Operations Update: First four HZ wells exceeding expectations Polar Bar recompletion results are encouraging Rich Gas Drill Plan: Drill & Complete 6 HZ wells Test spacing & delineate to the Northeast Test stacked lateral concept Gross Unrisked Resource Potential Spacing # Locations Tcfe 6 Middle/Lower Horizons (1) 1,800' ' Upper Horizon 1,800' ' Total 1,800' ' Asset Map Upper, Middle, and Lower Prospective Polar Bar Recompletion Middle and Lower Prospective Barricade 41-6 MH EUR: ~11.5 Bcfe Barricade 41-6 LH EUR: ~9 Bcfe HZ Producing Well Vertical Well (3 Zone Completion) Lower Target Middle Target Upper Target (1) Equal contribution from Middle and Lower Horizons Significant Resource Potential Delineation Continues, Sets Stage for Development Drilling in

10 Bakken Ambrose Field Overview Ambrose Field Asset Map 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 AMBROSE FIELD Q2 13 Production ~4,500 Boe/d Development Plans: Infill development in Ambrose Field; 8 wells per 1,280 acre unit (4 MB and 4 TF) Multi-well pads, three to six wells per pad D&C costs down 8% since 2012 Modeled Well Profile: Working Interest: ~41% D&C: ~$6.1 MM TVD: ~8,000 ; Lateral: 10,000 EUR: ~300 MBOE Samson Rigs Operated Acreage Non Operated Acreage Solid Oil-Weighted Position 10

11 CODY SHALE MESAVERDE Powder River Basin Asset Map by Field Targeted Zones Buffalo BLM Office North Tree Field LANCE FM. FOX HILLS SS LEWIS SS TEAPOT SS. PARKMAN SS. SUSSEX SS. (9,500 ) SHANNON SS. (10,000 ) STEELE SH. NIOBRARA SH. "CARLILE SH." WALL CR. SS. FRONTIER FM. (12,000 ) Helis Oil & Gas Spearhead Ranch Field Hornbuckle Field MOWRY SH. SHELL CREEK SH. MUDDY SS.(13,000 ) THERMOPOLIS SH. *Strat column from USGS Casper BLM Office Scott Field Samson Rigs Extensive Acreage Position Anchored by Shannon Development with Exploration Upside 11

12 Powder River Basin North Tree Field Overview Development Map Rig Count: Currently operating 2 rigs drilling multi-well pads targeting the Shannon formation in North Tree Field Acreage: ~17,000 net acres North Tree Activity: Drilled and completed 7 horizontal wells to test and delineate North Tree Field 7 well average Max IP of 1,440 BOPD and average IP30 of 429 BOPD (range BOPD) Development Plan: 2H 2013: 12 HZ wells from 4 pads using a combination of short and long reach laterals 2014: 16 HZ wells from 8 pads using a combination of short and long reach laterals Full Scale Potential North Tree Field 28 additional locations on 320 acre spacing Established Repeatability; 2013 Begins Development 12

13 Powder River Basin Sussex Overview Rig Count: Currently no active rigs. Two rigs currently planned to move from Green River back to Powder River to resume Sussex program in February 2014 Spearhead Ranch Sussex by Field Summary: Hornbuckle ~60,000 net acres 55 HZ producing Sussex wells in Hornbuckle, Spearhead, and Scott Fields Q2 13 Production: ~2,800 Boe/d Next Steps: 20 potential locations in 2014 Helis Oil & Gas Scott Continuing to delineate in Scott Field Additional locations dependent on further drilling results and defining down spacing potential Promising Economics in Delineated Fields 13

14 Powder River Basin Frontier Overview West Hornbuckle - Frontier Rig Count: Currently no active operated rigs Prospective Acreage: ~9,000 net acres (West Hornbuckle) Activity to Date: Bill Barrett, Helis and SM Energy currently actively drilling Samson has participated in 3 HZ Frontier wells Henry Fed H (BBG Operated) Henry Fed H (BBG Operated) Hornbuckle H (Helis Operated) Next Steps: Continue non-op participation to monitor opportunity of testing play with our own wells Continued success from others could lead to operated delineation program up to 6 wells Actively permitting for locations 39N 75W 38N 75W Helis Oil & Gas 37N 75W 36N 75W 39N 74W 38N 74W 37N 74W 36N 74W OBO Wells Samson Joined Potential Operated Drilling Locations Emerging Opportunity 14

15 Mid-Continent / East Texas Operations MC/ET Snapshot: Net Acreage: ~954,000 YE 2012 Proved Reserves: 1,235 Bcfe Q2 13 Average Daily Production: 362 MMcfe/d Oil 11%; NGL 14%; Gas 75% Current Rig Count: 6 Arkoma Basin: Mature Dry Gas Asset Q2 13 Production: 23 MMcfe/d Oklahoma East Texas / North Louisiana: Cotton Valley Sands Gas Option: Haynesville/Bossier Q2 13 Production: 177 MMcfe/d Rig Count: 2 Anadarko Basin: Liquids rich development targeting the Granite Wash and Marmaton plays Q2 13 Production: 162 MMcfe/d Rig Count: 4 Texas Louisiana Samson Rigs Legacy Position with Embedded Upside and Strong Natural Gas Option 15

16 Texas Oklahoma 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 ~200 potential stacked operated drilling locations Next Steps: 2H 2013 Plan: Test three pads with 2-4 stacked laterals each Reduce Well Costs: Average single well D&C $7.2 MM, currently targeting $6.5 MM via pad drilling Pounds 2 Well Pad Stacked GW Potential Hefley 4 Well Pad Transition to Pad Drilling Creates Potential for Long-Term Visibility Lister 3 Well Pad 2013 Planned Drilling Samson Rigs Potential Pad Drilling Locations Operated Acreage Non Operated Acreage 16

17 Marmaton Overview Rig Count: Currently operating 2 rigs in Black Kettle Activity Summary: ROGER MILLS Asset Map Black Kettle Six operated wells currently producing with strong results; liquids cut higher than expected in current focus area Maxon 2-13H IP 30: 1,300 BOPD; 6.4 MMCFD wet gas Continue 2 rig program into 2014 Key Goals and Next Steps: Reduce drill days / cost Test down dip and infill spacing - Success could yield an additional 30+ locations Estimated Well Profile: Working Interest: ~50% D&C: $7.9 MM TVD: 11,300 ; Lateral 5,000 Leon 3-10H IP 30: 1200 BOPD; 4.4 MMCFD wet gas Lea Erma 2-15H IP 30: 900 BOPD; 3.0 MMCFD wet gas Samson Rigs Key Wells EUR: 257 MBOE (66% liquids) Opportunistic Program with the Potential to Add Scale 17

18 Mississippi Lime Overview Asset Map Dietz & Cheyenne Valley Rig Count: Currently no active rigs Activity Summary: Drilled and completed 4 successful wells in our Dietz Area (one stacked lateral) Operating Update: 4 Well Avg. IP30 - ~290 BOPD Woods Dietz Area Production tracking above type curve; continue monitoring existing production in our Dietz area. Up to ~20 unrisked locations remaining Continue to evaluate play and adjacent opportunity sets (i.e. Cheyenne Valley) Dietz Area Estimated Well Profile: Woodward Major Garfield Kingfisher Working Interest: ~60% (Dietz Area) D&C: $5.6 MM Cheyenne Valley Area TVD: 6,900 ; Lateral 5,000 EUR: 300 MBOE (90% Liquids) Upper Mississippi Lower Mississippi Emerging Play with Promising Initial Results 18

19 East Texas Cotton Valley Cotton Valley Overview Rig Count: Operating 2 rigs in SE Carthage Field Cotton Valley Snapshot: Focus Area - Southeast Carthage Field Reeves 4 Well Pad (1 st Sales 9/29/2013) Acreage: ~31,000 net acres Primary Targets: CV C & B Sands Secondary Target: CV Taylor Twomey Heirs #3H (Cotton Valley C Completion) IP30-7,200 Mcfd & 450 BOPD Q2 13 Production: 78 MMcfe/d Operating Update: Continue focusing on SE Carthage liquids rich intervals; 29 locations remaining (as of 10/1) Werner-Caraway (7 Well Pad) D&C costs improving, down 8% since 2012 Complete two more wells by year end; 7 well pad sales expected 1Q 14 Modeled Well Profile CV C & B Sands: Working Interest: ~66% D&C: ~$5.5 MM 3-Stream EUR: Bcfe C Sand Target B Sand Target Samson Rigs Transition to Pad Drilling and Focus on Liquids-Rich Intervals has Led to Solid Returns 19

20 East Texas Cotton Valley Taylor Cotton Valley Taylor Overview Cotton Valley Taylor Current Plans: WOODLAWN Two wells scheduled in Q4 13 Q1 14 Four additional wells scheduled in 2014 HARRISON Drilling focused on targets with the highest liquids yields (~80% gas & 20% liquids) Cost saving efficiencies proven in drilling the CV C & B Sands will be utilized to RUSK PANOLA establish the economic viability of the CV Taylor program (~$7.5 MM in ) OAK HILL SCOTTSVILLE 70+ locations across core fields Expected Gas Quality: WH Btu Factor: WH NGL Yield: ~40 Bbl/MMcf WH Condensate Yield: 7 B/MM COBRA 2013 Planned Drilling 2014 Planned Drilling 20

21 Financial Strategy Committed to a Strong and Stable Capitalization Profile Target pre IPO leverage at or below 3.5x Maintain financial flexibility to execute on near-term capital plan Focus on maintaining solid liquidity position 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 Focus on oil / liquids-rich projects Improving liquids mix 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 21

22 Financial Position Debt Maturity Profile and Liquidity ($MM) 2020 $2, $1, $284 $1,496 RBL Capacity: $1.78B $0 $500 $1,000 $1,500 $2,000 $2,500 Revolver - Borrowings Revolver - Availability Second Lien Senior Notes (1) As of October 31, 2013, we had borrowings of ~$284 million on our revolver Sufficient Liquidity No Near-term Maturities (1) Revolver borrowings and availability excludes outstanding letters of credit 22

23 Current Hedge Position As of October 1, 2013 Gas Swaps Oil Swaps NGL Swaps Year MMBtu/d (1) Swap Price ,000 $ ,000 $ ,000 $ ,000 $ ,000 $3.92 Year Bbls/d (1) Swap Price ,750 $ ,500 $ ,500 $90.91 Year Bbls/d (1) Swap Price ,650 $ ,500 $34.78 Hedging Strategy Focused on Protecting Cash Flow From Expected Future Production 2013: Balance of year (1): Volumes are rounded 23

24 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, ,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, ,841 Loss on sale of other property and equipment 3,005-3,005 Adjustment for restructuring expenses (d) ,643 Adjustment for bad debt expense 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

25 Forward-Looking Statements All statements included in this presentation, other than statements of historical fact, may constitute forward-looking statements, including, but not limited to, statements or information regarding our future growth, results of operations, reserves, operational and financial performance, business prospects and opportunities and other 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 similar expressions are intended to identify forward-looking statements. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this presentation are forward-looking statements. All forward-looking statements involve risks and uncertainties. The occurrence of the events described and the achievement of the expected results depend on many events and assumptions, some or all of which are not predictable or within our control. 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 currently believe to be reasonable, actual results may differ materially from expected results. Factors that may cause actual results to differ from expected results include, but are not limited to: (i) fluctuations in oil and natural gas prices; (ii) the uncertainty inherent in estimating our reserves, future net revenues and PV-10; (iii) the timing and amount of future production of oil and natural gas; (iv) cash flow and changes in the availability and cost of capital; (v) environmental, drilling and other operating risks, including liability claims as a result of our oil and natural gas operations; (vi) proved and unproved drilling locations and future drilling plans; (vii) the effects of existing and future laws and governmental regulations, including environmental, hydraulic fracturing and climate change regulation; and (viii) any of the risk factors and other cautionary statements described in our Registration Statement on Form S-4, filed with the Securities and Exchange Commission (the SEC ) on February 14, 2013, and any other registration statements, reports or other information that we may subsequently file from time to time with the SEC. Readers are cautioned not to place undue reliance on forward-looking statements. Should one or more of the risks or uncertainties referred to 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. Further, new factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible to predict all such factors, or to the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. 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. Each forward-looking statement speaks only as of the date of this presentation, and we undertake no obligation to update or revise any forward-looking statements to reflect subsequent events or circumstances.