Investor Presentation December 2013
Company Overview Company Snapshot Focusing on Liquids-rich Targets in Existing Resource Base Proved Reserves (12/31/12): 2.0 Tcfe Q3 2013 Production (1) : 582 MMcfe/d (30% Liquids) Operated Rigs: 11 Total Net Acres: ~2.2 million Q3 13 Production by Area (1) (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 and Cotton Valley Sands Legacy Position: Haynesville / Bossier Rockies 219 East Texas 163 Mid-Con 200 As of 12/31/12 Reserves by Category PUD 35% PDNP 1% PDP 64% Samson Rigs Samson Office (HQ: Tulsa, OK) (1) Includes 11 MMcfe/d of production divested in Q3 13 2
Committed Leadership with Investor Support Industry Experience Public Company Experience Randy Limbacher - Chief Executive Officer and Director 32+ 32+ Richard Fraley - Executive Vice President and Chief Operating Officer 30+ 25 Phil Cook - Executive Vice President and Chief Financial Officer 25+ 17 Louis Jones - Executive Vice President of Business Development, New Ventures and Portfolio Management 30+ 30+ Andrew Kidd - Senior Vice President and General Counsel 20+ 10 Committed Equity Investors with Significant Industry Experience / Investment Exposure 3
Corporate Strategy Optimize Capital Program Maximize dollars at the drill bit Focus on prospects with higher liquids content to improve returns 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 18 24 months Non-core assets sales Divested over $300 million for 2013 YTD Long Term Opportunities to Strengthen Balance Sheet Equity contribution to fund growth from acquisitions or acceleration of delineated inventory Position portfolio for public market access 4
Maximizing Dollars to the Drill Bit Took active steps in early 2013 to reduce LG&G spending 2013 Strategy Capital by Type ($MM) LG&G $17 Facilities $39 (9ME 2013) 90% of capital to the drill bit in 2013 versus 76% in 2012 Focused capital dollars on liquids weighted D&C $487 projects Capital Spend Year over Year Comparison D&C Capital by Division (%) $543 Million ($MM) (9ME 2013) $800 $600 $720 $173 $543 East Texas (14%) $56 $400 $200 $547 76% $487 90% Rocky Mountains (51%) Mid- Continent (35%) $0 9ME 2012 9ME 2013 D&C LG&G & Other 5
Maintaining Base Production MMcfe/d 700 600 500 400 300 607 605 604 572 568 574 571 200 100 0 Q1'12 Q2'12 Q3'12 Q4'12 Q1'13 Q2'13 Q3'13 (1) Divested (1) Production normalized for divestitures since January 2012 6
Delivering Liquids Growth (MBbl/d) 35 Liquids Production by Quarter (1) (% Liquids) 35% 30 29% 30% 30% 26% 25 20 19% 21% 23% 15 15 25% 20% 15 9 11 12 13 15% 10 10% 5 9 11 11 11 13 14 5% 0 Q1'12 Q2'12 Q3'12 Q1'13 Q2'13 Q3'13 NGL (MBbl/d) Oil (MBbl/d) %liquids 0% (1) Excludes production associated with all divestitures in 2012 and 2013 to date 7
D&C Costs per Well ($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 $5.0 2012 2013 YTD 2012 2013 YTD Bakken - Ambrose Field Cotton Valley - SE Carthage Driving Down Costs Across the Portfolio Note: 2013 YTD represents wells completed through August for Bakken and September for Cotton Valley 8
Improving Relative Cost Structure Commitment to Continual Improvement Lease Operating Expense Down despite shift to higher cost liquids focused drilling Cash G&A (1) Reduced compensation expense Lease Operating Expense Cash G&A (1) ($ per Mcfe) ($ MM) $0.94 $100 $94 $84 $0.93 $0.93 $75 $0.92 $50 $0.91 $0.91 $25 $0.90 9ME 2012 9ME 2013 $0 9ME 2012 9ME 2013 (1) Income Statement G&A excluding non-cash compensation 9
Asset Sales Balance Sheet Protection $MM $800 $680 Asset Sales $600 $400 ~$300 $200 $200+ $0 2012 2013 (E) 2014 (E) 10
Asset Overview 11
Rocky Mountain Operations Rocky Mountains Snapshot: Net Acreage: ~1,000,000 YE 2012 Proved Reserves: 779 Bcfe Q3 13 Average Daily Production (1) : 219 MMcfe/d Oil 23%; NGL 13%; Gas 64% Current Rig Count: 5 North Dakota Powder River Basin: Williston Basin: Three Forks and Middle Bakken development Q3 13 Production: 4.2 MBoe/d Rig Count: 1 Idaho Wyoming Stacked oil plays targeting: Shannon, Sussex, Muddy, and Frontier Q3 13 Production: 3.6 MBoe/d Rig Count: 2 Green River Basin: Utah Colorado Horizontal program in the Ft. Union Q3 13 Production: 77 MMcfe/d Rig Count: 2 San Juan Basin: Samson Rigs Mature dry gas asset Q3 13 Production: 95 MMcfe/d Diversified Position Across Several Basins with Catalysts for Growth (1) Includes 11 MMcfe/d of production divested in Q3 13 12
Green River Basin Ft. Union Overview Rig Count: Currently operating 2 rigs Acreage: 39,900 Gross / 32,000 Net Q3 13 Production: 43 MMcfe/d Operations Update: First four HZ wells exceeding initial expectations Polar Bar recompletion results are encouraging 2013-2014 Drilling Season: Drill & Complete 6 HZ wells Test spacing & delineate to the Northeast Test stacked lateral concept Potential to add rig in 2014 Asset Map Upper, Middle, and Lower Prospective Middle and Lower Prospective Barricade 41-6 MH EUR: ~11.5 Bcfe Barricade 41-6 LH EUR: ~9 Bcfe Gross Unrisked Resource Potential Polar Bar Recompletion Horizons Spacing # Locations Gross Tcfe 6 Lower/Middle/Upper 1,800' 173 1.5 Lower/Middle/Upper 900' 346 3.0 HZ Producing Well Vertical Well (3 Zone Completion) 2013-2014 Lower Target 2013-2014 Middle Target 2013-2014 Upper Target Significant Resource Potential Delineation Continues, Sets Stage for Development Drilling in 2014 13
Mid-Continent / East Texas Operations MC/ET Snapshot: Net Acreage: ~954,000 YE 2012 Proved Reserves: 1,235 Bcfe Q3 13 Average Daily Production: 363 MMcfe/d Oil 11%; NGL 16%; Gas 73% Current Rig Count: 6 Arkoma Basin: Mature Dry Gas Asset Q3 13 Production: 23 MMcfe/d Oklahoma East Texas / North Louisiana: Cotton Valley Sands Gas Option: Haynesville/Bossier Q3 13 Production: 163 MMcfe/d Rig Count: 2 Anadarko Basin: Liquids rich development targeting the Granite Wash and Marmaton plays Q3 13 Production: 177 MMcfe/d Rig Count: 4 Texas Louisiana Samson Rigs Legacy Position with Embedded Upside and Strong Natural Gas Option 14
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: 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 Waiting on completion Lister 3 Well Pad Samson Rigs Potential Pad Drilling Locations Operated Acreage Non Operated Acreage Transition to Pad Drilling Creates Potential for Long-Term Visibility 15
Financial Position Balance Sheet Committed to improving leverage Maintain 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 (reaffirmed November 2013) 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 16
Summary Focusing on Key Building Blocks for the Future Constructing key processes & business systems Focusing on costs, capital discipline & asset sales resulting in improved debt metrics & returns Active in M&A deal flow as we seek to optimize the portfolio & provide opportunities to deleverage the company Significant potential to add value Long term natural gas option in East Texas and Mid-Continent Ft. Union has upside potential to more than double current proven reserves Testing multi-year drilling potential in Granite Wash Exploration upside from large land position 17
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.
Appendix
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 Carolina (4 Well Pad) 7 well average Max IP of 1,440 BOPD and average IP30 of 429 BOPD (range 184-807 BOPD) Development Plan: 2H 2013: 12 HZ wells from 4 pads using a combination of short and long reach laterals Missouri (4 Well Pad) 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 2011-2012 Established Repeatability; 2013 Initiated Development 20
Mid-Continent Operations Mid-Continent Snapshot: Net Acreage: ~574,000 YE 2012 Proved Reserves: 627 Bcfe Q3 13 Average Daily Production: 200 MMcfe/d Oil 17%; NGL 21%; Gas 62% Current Rig Count: 4 Samson Rigs Legacy Position Continues to Yield New Opportunities 21
Marmaton Overview Asset Map Black Kettle Rig Count: Currently operating 2 rigs in Black Kettle ROGER MILLS Activity Summary: 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 Leon 3-10H IP 30: 1,200 BOPD; 4.4 MMCFD wet gas Lea Erma 2-15H IP 30: 800 BOPD; 3.0 MMCFD wet gas Samson Rigs Key Wells Opportunistic Program with the Potential to Add Scale 22
East Texas Operations East Texas Snapshot: Net Acreage: ~380,000 YE 2012 Proved Reserves: 608 Bcfe Q3 13 Average Daily Production: 163 MMcfe/d Oil 3%; NGL 10%; Gas 87% Current Rig Count: 2 Liquids Rich and Dry Gas Producing Properties Samson Rigs 23
East Texas Cotton Valley Cotton Valley Overview Focus Area - Southeast Carthage Field Rig Count: Operating 2 rigs in SE Carthage Field Cotton Valley Snapshot: Acreage: ~31,000 net acres Primary Targets: CV C & B Sands Secondary Target: CV Taylor Q3 13 Production: 71 MMcfe/d Operating Update: Continue focusing on SE Carthage liquids rich intervals; 29 locations remaining (as of 10/1) D&C costs improving, down 8% since 2012 Complete three more wells by year end; 7 well Werner-Caraway pad sales expected Q1 14 Modeled Well Profile CV C & B Sands: Working Interest: ~66% D&C: ~$5.5 MM 3-Stream EUR: 5.1 7.4 Bcfe Reeves 4 Well Pad Avg IP30 4.0 MMCFD & 80 BOPD Biggs (3 Well Pad) Werner-Caraway (7 Well Pad) C Sand Target B Sand Target Samson Rigs Transition to Pad Drilling and Focus on Liquids-Rich Intervals has Led to Solid Returns 24
Financial Position Debt Maturity Profile and Liquidity ($MM) 2020 $2,250 2019 2018 $1,000 2017 2016 $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 25
Current Hedge Position As of November 15, 2013 Gas Swaps Oil Swaps NGL Swaps Year MMBtu/d (1) Swap Price 2013 330,000 $3.75 2014 309,000 $4.15 2015 92,000 $4.09 2016 86,000 $4.08 2017 40,000 $3.92 Year Bbls/d (1) Swap Price 2013 17,750 $92.82 2014 16,500 $90.63 2015 3,500 $90.91 Year Bbls/d (1) Swap Price 2013 8,650 $35.81 2014 6,000 $34.94 Hedging Strategy Focused on Protecting Cash Flow From Expected Future Production 2013: Balance of year (1): Volumes are rounded 26
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 (a) 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 (b) 8,780 19,864 36,494 Adjustment for fees paid to co-investors (c) 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 (d) - - 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 (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) 27