J.P. Morgan High Yield Leveraged Finance Conference February 24-26, 2014
Forward-Looking & Other Cautionary Statements Preliminary Operational and Financial Data In this presentation, Samson Resources Corporation (the Company or we ) provides preliminary unaudited operational and financial information for the fourth quarter 2013 and fiscal year 2013. We prepared this preliminary data based on the most current information available to management. The Company s normal closing and financial reporting processes with respect to the preliminary operational and financial information have not been fully completed and, as a result, actual results could be different from the preliminary information presented, and any such differences could be material. 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 capital expenditures, production, 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. 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 forwardlooking 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. Reserves Disclaimer The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves that a company has demonstrated by actual production or through reliable technology to be economically and legally producible at specific prices and existing economic and operating conditions. The Company may use the terms resource potential and EUR in this presentation to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with the SEC. These quantities do not constitute reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or SEC rules. EUR, or estimated ultimate recovery, refers to our management s internal estimates based on per well hydrocarbon quantities that may be potentially recovered from a hypothetical future well completed as a producer in the area. Estimates of resource potential and EUR are by their nature more speculative than estimates of proved reserves, and, accordingly, are subject to substantially more risk of actually being realized. Actual quantities that may be ultimately recovered may differ materially from the estimates contained in this presentation. Factors affecting ultimate recovery include our ability to acquire the acreage we are targeting and the scope of our on-going drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of resource potential, per well EUR and drilling locations may change significantly as the Company pursues acquisitions. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. 2
Company Overview Company Snapshot Focusing on Liquids-Rich Targets Across Current Asset Base Proved Reserves (1) : 2.0 Tcfe Q4 13E Production: 543 MMcfe/d Operated Rigs: 10 Total Net Acreage (2) : ~2 million West Division Q4 13E Production: 190 MMcfe/d Proved Reserves (1) : 779 Bcfe Acreage: 823,000 West Division Business Units: Williston Three Forks / Middle Bakken Powder River Shannon, Frontier, Sussex Greater Green River Ft. Union San Juan Legacy dry gas position East Division Q4 13E Production: 353 MMcfe/d Proved Reserves (1) : 1,235 Bcfe Acreage: 932,000 East Division Business Units: Mid-Continent West Granite Wash Mid-Continent East Marmaton, MS Lime East Texas Cotton Valley Sands Samson Operated Rigs Samson Offices (HQ: Tulsa, OK) (1) NSAI YE 2012 (2) As of YE 2013, includes ~200,000 net acres of certain non-core assets which are not included in the West and East Division totals 3
Corporate Strategy Optimize Capital Program Maximize dollars at the drill bit Focus on projects with higher liquids content to improve returns Reduce costs and improve efficiencies in the field Add Additional 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 Protect the Balance Sheet Disciplined and targeted approach to exploration spending Well hedged for the next 12 months Non-core assets sales Position for Access to Additional Sources of Capital Equity contribution from existing investors to fund growth from acquisitions or acceleration of delineated inventory Actively manage the portfolio for public market access 4
Days $/ft Preliminary 2013 Key Operational Highlights Allocated 90+% of capital to the drill bit 2013 Operated Wells Drilled (1) Balanced approach between delineation efforts in the Greater Green River, Powder River and Midcon with development dollars to East Texas and Williston Continued focus on driving down cost structure across the portfolio Williston 35 Powder River 18 Midcon West 17 East Texas 22 Green River 7 Midcon East 20 119 Gross Operated Wells Average Days Spud to Total Depth (2) Average Spud to Total Depth Cost per Foot (2) 80 70 67 $700 $600 $609 60 50 40 30 20 10 36 20 12 31 25 $500 $400 $300 $200 $100 $358 $190 $124 $211 $184 0 2012 2013 2012 2013 2012 2013 Ft. Union Bakken Cotton Valley $0 2012 2013 2012 2013 2012 2013 Ft. Union Bakken Cotton Valley (1) Wells spud in 2013 (2) Compares wells in 2012 to wells in 2013 that reached total depth 5
Preliminary 2013 Production Summary 450 425 400 375 350 325 436 Gas (MMcfe/d) (MMcf/d) 425 409 385 20 15 10 11.6 NGL (MBbl/d) 12.9 14.1 12.7 20 15 10 14.3 Oil (MBbl/d) 15.5 14.8 13.7 650 600 550 500 591 595 23.9 21.9 Total (MMcfe/d) 582 12.0 Avg. 578 (1) 543 1.2 300 275 250 225 5 5 450 400 200 Q1'13 Q2'13 Q3'13 Q4'13 0 Q1'13 Q2'13 Q3'13 Q4'13 0 Q1'13 Q2'13 Q3'13 Q4'13 2013 Avg Gas 413 MMcfe/d 2013 Avg NGL 12.8 MBbl/d 2013 Avg Oil 14.6 MBbl/d 350 Q1'13 Q2'13 Q3'13 Q4'13 Divested Production (% liquids) 30% 25% 20% 15% 10% 5% 0% Pro Forma Liquids Mix Improving (2) 2013 Production by Business Unit (1) 22% 29% 2012 2013 (1) YE 2013 production includes 15 MMcfe/d of divested production (2) Pro forma for divested production Powder River 4% San Juan 17% MC West 16% Williston 4% MC East 17% East Texas 30% Green River 12% 578 MMcfe/d 6
2014E Capital Plan 2014 Base Capital Plan $729 MM Total D&C capital of $671 MM Drill Bit Focused (1) ($MM) Other $58 (8%) Rig count consistent with 2013 activity levels Expect to spud 127 gross operated wells during 2014 D&C $671 (92%) Key Area Highlights: Increasing Ft. Union and Shannon activity Granite Wash multi-well pad delineation continues Testing Cotton Valley Taylor and further delineating Marmaton Opportunistically spend on exploration Non-core asset sales $150 $200 MM San Juan 1% Williston 12% Powder River 27% D&C by Area MC - West 18% East Texas 18% Green River 10% MC - East 14% $729 MM $671 MM (1) Excludes capitalized interest and internal costs. Other includes LGG ($15mm), Facilities ($28mm) and Corporate ($15mm) 7
(MMcfe/d) (MMcfe/d) 2014E Production Guidance 600 85-95 85-92 77 545-595 549-589 578 500 95-105 97-104 400 367-394 365-395 413 87 300 200 100 0 Gas Oil NGL Total Note: All numbers independently rounded Denotes high/low range Denotes 2013 actual (inclusive of divested volumes) 8
Asset Overview
West Division Overview Williston Basin Bakken oil / horizontal infill development Powder River Basin Exploration and development of multiple prospective oil horizons Greater Green River Basin Ft. Union early stage development / high impact liquids-rich gas play San Juan Basin Mature legacy dry gas position Rig Count: 4 rigs (3 PRB / 1 Williston) Acreage: 823,000 Net / 48% HBP Q4 13E Production: 190 MMcfed (35% Liquids) Proved Reserves (1) : 779 Bcfe Overview Map WYOMING Greater Green River Williston NORTH DAKOTA Q4 13E Production: 52 MMcfe/d Acreage: 252,000 Q4 13E Production: 4.0 MBoe/d Acreage: 180,000 Powder River Q4 13E Production: 3.5 MBoe/d Acreage: 310,000 2014 Base Drilling Plan: Operated Wells (2) : Gross 64 / Net 40 Net D&C Capital: $336 million (87% operated) COLORADO San Juan Q4 13E Production: 93 MMcfe/d Acreage: 82,000 SAMSON OPERATED RIGS (1) NSAI YE 2012 (2) Spud CY 2014 10
Greater Green River Ft. Union Overview Liquids-rich gas play with high impact potential Overview Map Currently targeting three intervals of stacked sand in the Ft. Union reservoir with approximately 1,000 of gross interval 11-21 Developing via multi-well horizontal pads with TVD of ~10,500 and a lateral length of ~4,500 Currently seven horizontal and 17 vertical wells producing First sales on two additional new horizontals expected Q1 14 (Barricade 24-36 pad one middle and one lower) 24-36 22-06 42-30S Endurance 41-29 3 Well Pad Upper, Middle, Lower First Sales 2/2014 Rig Count: 3 rigs (drill window Aug 14-Feb 15) Acreage: 39,900 Gross / 32,000 Net Barricade 41-6 2 Well Pad First Sales Q1 13 41-6 Middle EUR: ~11.5 Bcfe 41-6 Lower EUR: ~9 Bcfe Q4 13E Production: 31 MMcfe/d (54% Liquids) 2014 Base Drilling Plan: Operated Wells (1) : Gross 9 / Net 6 Net D&C Capital: ~$65 million (100% operated) Gross Unrisked Resource Potential Horizons Spacing # Locations Gross Tcfe 6 Lower/Middle/Upper 1,800' 173 1.5 Lower/Middle/Upper 900' 346 3.0 Lower Target Middle Target Lower & Upper Target Lower & Middle Target 2014 Planned Drilling Completion in Progress or Recent First Sales Producing Horizontals Producing Vertical (1) Spud CY 2014 11
Days $ MM Ft. Union Reducing Drill Days and Cost Average Days Spud to Total Depth (1) Average Drilling Cost Spud to Total Depth (1) 80 $10 70 67 $8.9 60 $8 50 40 36 $6 $5.2 30 $4 20 $2 10 0 2012 2013 $- 2012 2013 E (1) 2012 comprised of the Barricade 41-6M, 41-6L and Barricade 21-11. 2013 comprised of the Endurance 41-29 three well pad and Barricade 24-36 three well pad 12
Powder River Basin Overview Overview Map Powder River Zones (Competitors Drilling) Multiple pay basin characterized by both conventional (Shannon, Sussex, Frontier) and unconventional (Mowry, Niobrara) oil targets ranging from 7,500-13,000 Current activity focused on HZ development at North Tree Field (Shannon) & Hornbuckle Field (Sussex); industry activity remains strong with focus on multiple plays JOHNSON North Tree Field CAMPBELL Peak Powder River Resources SUSSEX SS. SHANNON SS. (BBG) STEELE SH. NIOBRARA SH. (RKI Exp, CHK, EOG) "CARLILE SH." WALL CR. SS. FRONTIER FM. (DVN, APC, BBG, SM, Helis) Evaluating/testing emerging Frontier play *Strat column from USGS Extensive G&G study underway Rig Count: 3 rigs (2 North Tree / 1 Hornbuckle) Acreage: 310,000 Net / 45% HBP Hornbuckle Field Q4 13E Production: 3.5 MBoe/d NATRONA 2014 Base Drilling Plan: Operated Wells (1) : Gross 28 / Net 20 Net D&C Capital: ~$180 million (85% operated) CONVERSE ACTIVE RIG (1) CY 2014 Spud 13
Powder River Basin North Tree Field Overview Seven producing horizontal Shannon oil wells Development Map HZ pad development via short (1 mile) and long (2 mile) laterals with TVD of ~10,500 First sales expected on ten wells in Q1 14 (seven long laterals and three short); costs in-line with AFE d amount CY 2014 plan includes 11 short laterals and 5 long laterals (1) JOHNSON Rig Count: 2 rigs Acreage: 25,000 Gross / 17,000 Net CAMPBELL NORTH TREE Recent Well Results: Well Name First Sales D&C IP30 (2) Lateral TCR Kentucky Q2 13 $7.9MM 730 BOED 1 mile Springfield TCR Springfield Q1 13 $7.0MM 200 BOED 1 mile DF Nebraska Q1 13 $9.6MM 810 BOED 1 mile DF Nebraska Iowa Pad Kentucky 2014 Base Drilling Plan: Carolina Pad Operated Wells (1) : Gross 16 / Net 12 Net D&C Capital: ~$105 million (100% operated) ACTIVE RIG Tennessee Pad 2014 PLAN 2013 WIP PRODUCING WELL (BHL) (1) CY 2014 Spud (2) Two Stream 14
Williston Basin Overview Spud 35 gross operated horizontal wells in 2013 D&C well costs down nearly 10% from 2012 to 2013 One rig program focused on horizontal pad infill development (Middle Bakken and Three Forks) Continue focusing on efficiency and cost reduction (e.g. multi-well pads, batch drilling and centralized facilities) Pilot testing new completion design Ambrose Field (Divide County) Development Rig Count: 1 rig Acreage (1) : 77,000 Net / 75% HBP / 55% Operated Q4 13E Production: 4.0 MBoe/d 2014 Base Drilling Plan: Almos Farms 0112-4H IP30: 451 BOPD Charger 0706-1TFH IP30: 463 BOPD Operated Wells (2) : Gross 23 / Net 11 Net D&C Capital: ~$85 million (83% operated) AMBROSE FIELD 2014 PLAN OPERATED ACREAGE PRODUCING NON-OP ACREAGE ACTIVE RIG (1) Divide County, ND only (2) CY 2014 Spud 15
East Division Overview Targeting liquids-rich intervals across acreage position Testing pad drilling approach in the Granite Wash; cost structure key to optimizing resource potential Continue infill development of the CV B & C sands Further delineate Marmaton and MS Lime Testing CV Taylor in 2014 Rig Count: 6 rigs (2 GW/ 2 Marmaton / 2 CV) Acreage (1) : 932,000 Net / 92% HBP Q4 13E Production: 353 MMcfe/d (26% Liquids) Proved Reserves (2) : 1,235 Bcfe Overview Map Mid-Continent West Q4 13E Production: 88 MMcfe/d Acreage: 232,000 TEXAS Mid-Continent East Q4 13E Production: 102 MMcfe/d Acreage: 335,000 OKLAHOMA 2014 Base Drilling Plan: Operated Wells (3) : Gross 63 / Net 44 Net D&C Capital: ~$334 million (88% operated) East Texas Q4 13E Production: 163 MMcfe/d Acreage (1) : 365,000 (1) Includes Permian minerals of 67,000 net acres (2) NSAI YE 2012 (3) CY 2014 Spud 16
Mid-Continent West Granite Wash Overview Overview Map Targeting liquids-rich stacked pay in the Granite Wash with 12 distinctive producing horizons Spud 16 (1) single well HZ pads in 2013 Transitioning from single well horizontal development to Pounds (2 Well Pad) HEMPHILL multi-well pad development; focusing on D&C cost reductions to unlock inventory/resource potential Initial sales results from 2013 multi-well pads expected during Q1 14; D&C costs trending slightly under AFE Hefley (4 Well Pad) Rig Count: 2 rigs Acreage (1) : 56,000 Net / 89% HBP Q4 13E Production (1) : 67 MMcfe/d 2014 Base Drilling Plan: Operated Wells (3) : Gross 23 / Net 15 Net D&C Capital: ~$120 million (88% operated) Lister (3 Well Pad) (2) First Sales: Q4 13 D&C: $6.0MM avg per Well IP30: 3.5 MMcfe/d (69% Liquids) WHEELER (1) Wheeler and Hemphill Counties only (2) Hogshooter, Cottage Grove and Upper Granite Wash (3) CY 2014 Spud 2014 Plan Recent Well Active Rig Stacked Granite Wash Douglas Hogshooter Cottage Grove 17
Oklahoma Texas Mid-Continent East Marmaton Overview Eleven horizontal operated wells producing Overview Map Continue developing through 2014 while delineating play further south / down dip Develop via single well and two well horizontal pads Leon 3-10H Lee 2-11H First Sales 2/2014 Roger Mills (TVD 11,300 & Lateral 4,500 ) Successful spacing and down dip tests could yield 30+ locations Maxon 4-13H Rig Count: 2 rigs Recent Well Results: Well Name First Sales D&C IP30 (2) % Liquids (2) Purvis 2-19H Q4 13 $8.6MM 13.4 MMcfe/d 23% Purvis 2-19H Maxon 4-13H Q4 13 $8.1MM 6.9 MMcfe/d 43% Roger Mills Leon 3-10H Q3 13 $9.9MM 11.5 MMcfe/d 62% 2014 Base Drilling Plan: Operated Wells (1) : Gross 8 / Net 5 Net D&C Capital: ~$53 million (89% operated) 2014 PLAN PRODUCING WELLS ACTIVE RIG WOC (1) CY 2014 Spud (2) Two Stream 18
East Texas Cotton Valley Overview Overview Map Spud 22 HZ wells at SE Carthage in 2013 D&C well costs down nearly 10% from 2012 to 2013 Harrison Continue development of the liquids-rich CV B and C sands into 2014 (spud 17 wells) Testing Cotton Valley Taylor program (spud four wells) Gregg Panola Werner Husband 3, 4 & 5 (3 Well Pad) First Sales Q1 14 IP30: 4.8 MMcfe/d D&C costs key to unlocking economic inventory Ten CV B & C wells expected to have first sales in Q2 14 Rusk Panola SE Carthage Field Biggs (3 Well Pad) Rig Count: 2 rigs Acreage (1) : 86,000 Net / 98% HBP Q4 13E Production (1) : 84 MMcfe/d Louis Werner 7 & 8 (2 Well Pad) First Sales Q4 13 IP30: 4.5 MMcfe/d Reeves (3 Well Pad) Werner Caraway (7 Well Pad) 2014 Base Drilling Plan: Operated Wells (2) : Gross 21 / Net 18 Net D&C Capital: ~$120 million (97% operated) 2014 CV Taylor Wells Recent CV B & C Wells C Sand Target B Sand Target Active Rigs (1) Rusk, Harrison, Gregg & Panola Counties only (2) CY 2014 Spud 19
Cotton Valley B & C Reducing Well Costs $6.5 $6.0 $5.5 $5.0 $4.5 Drilling & Completion Costs (1) ($MM) 6.1 5.6 Average spud to total depth times have been reduced from 31 days in 2012 to 25 days in 2013 (20% reduction) Multi-well pad drilling, walking rigs and batch drilling have driven cost saving efficiencies in SE Carthage $4.0 $3.5 $3.0 2012 2013 (1) Based on spud wells in 2012 and 2013 20
Financial Position Balance Sheet Committed to improving leverage Maintain adequate liquidity position Simple capital structure with no near term maturities Access equity capital to delever with a growth focused acquisition or acceleration of organic development Bank Credit Facility Diversified bank group 24 banks with no bank over 10% Borrowing base of $1.78 billion Hedge Position Maintain a solid hedge position to protect capital program by reducing price risk Over 70% hedged on a total hydrocarbons basis for 2014 Initial positions established for 2015 21
Debt Maturity Profile and Liquidity Highlights Sufficient liquidity, no near term maturities Debt Maturity Profile and Liquidity ($MM) January 31, 2014, we had borrowings of $344 million on our revolver (1) 2020 $2,250 Debt Tranches Sr. Notes $2.25Bn Due February 2020 Coupon 9.75% (2) 8 year / NC 4 2 nd Lien Term Loan $1.0Bn Due September 2018 Libor plus 4.00% (LF = 1.00%) RBL Credit Facility Matures December 2016 Borrowing Base $1.78 Bn Grid based rates (1.50%-2.50%) Covenant Debt to Adjusted EBITDA 2014 5.50x 2015 5.00x 2016 4.50x 2019 2018 2017 2016 $1,000 $344 $1,436 RBL Capacity: $1.78B $0 $500 $1,000 $1,500 $2,000 $2,500 Revolver - Borrowings Revolver - Availability(1) Second Lien Senior Notes (1) Revolver borrowings and availability excludes outstanding letters of credit (2) Currently paying additional interest due to delay in registering notes 22
Current Hedge Position As February 5, 2014 Natural Gas Swaps & Collars Oil Swaps NGL Swaps Year MMBtu/d (1) Wtd Avg Floor 2014 308,000 $4.15 2015 (2) 127,170 $4.09 2016 (3) 116,000 $4.06 2017 40,000 $3.92 Year Bbls/d (1) Swap Price 2014 16,500 $90.63 2015 3,500 $90.91 Year Bbls/d (1) Swap Price 2014 7,500 $35.62 (1) Volumes are rounded (2) 2015 includes 20,000 MMBtu/d of Cal 15 collars and 10,000 MMBtu/d of Q1 15 collars (3) 2016 includes 30,000 MMBtu/d of natural gas collars to the extent our counterparty elects to exercise their collar options Note: 2014 includes balance of the year only 23
Adjusted EBITDA Reconciliation Three Months Nine Months Twelve Months Ended Ended Ended September 30, 2013 September 30, 2013 September 30, 2013 Net income (loss) $ 6,657 $ 31,472 $ (1,096,163) Interest expense, net - - - Provision (benefit) for income taxes 4,110 17,757 (567,653) Depreciation, depletion and amortization (1) 129,438 386,468 571,991 EBITDA $ 140,205 $ 435,697 $ (1,091,825) Adjustment for unrealized hedging losses (gains) 32,304 14,367 (32,331) Adjustment for non-cash stock compensation expense (2) 8,780 19,864 36,494 Adjustment for fees paid to co-investors (3) 5,250 15,750 20,750 Adjustment for fees paid for public company compliance 427 2,704 2,917 (Gain) loss on sale of other property and equipment (2,796) 209 209 Adjustment for restructuring expenses (4) - - 46,643 Adjustment for bad debt expense - - 62 Provision to reduce carrying value of oil and gas properties - 80,330 1,772,870 Unusual or non-recurring charges described in credit agreement 8,585 17,161 17,161 Adjusted EBITDA $ 192,755 $ 586,082 $ 772,950 Consolidated Adjusted EBITDA (5) $ 739,375 (1) Includes depreciation, depletion and amortization of oil and gas properties and depreciation and amortization of other property and equipment. (2) Stock compensation expense recognized in earnings, net of capitalization (3) Quarterly management fee (4) Total expenses incurred in Q4 12 related to the restructuring (including the RIF) (5) Excludes sold EBITDA per Credit Agreement 24