EnerCom s The Oil & Gas Conference 17

Transcription

1 EnerCom s The Oil & Gas Conference 17 August 14, 2012

2 Forward-Looking Statements This communication contains forward-looking information regarding Halcón Resources that is intended to be covered by the safe harbor for "forward-looking statements" provided by the Private Securities Litigation Reform Act of Forward-looking statements are based on Halcón Resources current expectations beliefs, plans, objectives, assumptions and strategies. Forwardlooking statements often, but not always, can be identified by using words such as "expects", "anticipates", "plans", "estimates", "potential", "possible", "probable", or "intends", or where Halcón Resources states that certain actions, events or results "may", "will", "should", or "could" be taken, occur or be achieved. Statements concerning oil, natural gas liquids and gas reserves also may be deemed to be forward-looking in that they reflect estimates based on certain assumptions including that the resources involved can be economically exploited. Forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to: operational risks in exploring for, developing and producing crude oil and natural gas; uncertainties involving geology of oil and natural gas deposits; the timing of and potential proceeds from planned divestitures; uncertainty of reserve estimates; uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters; uncertainties as to the availability and cost of financing; fluctuations in oil and natural gas prices; risks associated with derivative positions; inability to realize expected value from acquisitions, inability of our management team to execute plans to meet our goals; shortages of drilling equipment, oil field personnel and services; unavailability of gathering systems, pipelines and processing facilities; and the possibility that laws, regulations or government policies may change or governmental approvals may be delayed or withheld. Additional information on these and other factors which could affect Halcón Resources' pro forma operations or financial results are included in Halcón Resources reports on file with the SEC and filings made by GeoResources Inc. with the SEC. Investors are cautioned that any forward-looking statements are not guarantees of future performance and actual results or developments may differ materially from the projections in the forward-looking statements. Forward-looking statements are based on assumptions, estimates and opinions of management at the time the statements are made. Halcón Resources does not assume any obligation to update forward-looking statements should circumstances or such estimates or opinions change. 2

3 Cautionary Statement Regarding Hydrocarbon Quantities The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves, however, we currently do not disclose probable or possible reserves in our SEC filings. We 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 are based on the Company s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. 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. For areas where the company has no or very limited operating history, EURs are based on publicly available information relating to operations of producers operating in such areas. For areas where the company has sufficient operating data to make its own estimates, EURs are based on internal estimates by the company s management and reserve engineers. Drilling locations represent the number of locations that we currently estimate could potentially be drilled in a particular area determined by dividing the mid-points of the numbers of our targeted acreage acquisitions by the estimated well spacing requirements applicable to that area. We have not completed acreage acquisitions in some of our targeted areas. Actual acreage acquired, locations drilled and quantities that may be ultimately recovered from the Company s interests will differ substantially. There is no commitment by the Company to drill all of the drilling locations which have been attributed these quantities. Factors affecting ultimate recovery include our ability to acquire the acreage we are targeting and the scope of our ongoing 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. 3

4 Liquids-Rich Asset Base and Significant Drilling Inventory Bakken 2 Liquids-Rich Exploratory Plays Not Shown Mississippi Lime Utica/Point Pleasant Woodbine/Eagle Ford PF Total Proved Reserves: 72.8 MMBoe PF % Developed: 55% PF % Oil/NGLs: 74% PF 2Q12 Avg. Net Daily Production: 14,862 Boe PF Total Proved PV10: $1,576.3 MM PF Resource Potential: ~1.3 BBoe Midway/Navarro TMS Wilcox Note: Production and proved reserves pro forma for GeoResources Merger and the acquisition of the East Texas Assets. Pro forma proved reserves data consist of (i) proved reserves for Halcón as of , as estimated by Halcón s independent reserve engineers, (ii) proved reserves of GeoResources as of as estimated by GeoResources independent reserve engineers (except for certain Austin Chalk reserves acquired in the first quarter of 2012, which were estimated by GeoResources internal reserve engineers) and (iii) proved reserves attributable to the East Texas Assets as of , as estimated by Halcón s internal reserve engineers using unweighted average first-day-of-the-month commodity prices for the year ended and otherwise in accordance with SEC rules relating to reporting of reserves. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of resource potential. 4

5 Mboe Boe/d Substantial Production and Reserves Growth Average Daily Production 40,000 30,000 >373% >135% >89% 20,000 >280% 10, ,000 60,000 (1) 2Q12 2Q12 PF 4Q12E 2013E Proved Reserves >245% 40,000 20,000 0 HK 68% Liquids HK PF (2) 74% Liquids Oil NGLs Gas (1) Includes GeoResources and East Texas Assets acquisitions. (2) Proved reserves pro forma for GeoResources and East Texas Assets acquisitions. Pro forma proved reserves data consist of (i) proved reserves for Halcón as of , as estimated by Halcón s independent reserve engineers, (ii) proved reserves of GeoResources as of as estimated by GeoResources independent reserve engineers (except for certain Austin Chalk reserves acquired in the first quarter of 2012, which were estimated by GeoResources internal reserve engineers) and (iii) proved reserves attributable to the East Texas Assets as of , as estimated by Halcón s internal reserve engineers using unweighted average first-day-ofthe-month commodity prices for the year ended and otherwise in accordance with SEC rules relating to reporting of reserves. 5

6 Building An Oil Company Targeted Net Acres (1) Progress First Spud Targeted Areas Utica/Point Pleasant 150, ,000 ~80% 3Q12 Woodbine/Eagle Ford 150, ,000 ~85% May TMS 150, ,000 ~30% 3Q12 Bakken 55, ,000 ~60% N/A Mississippi Lime 50, ,000 ~60% April Wilcox 50, ,000 ~100% 4Q12 Midway/Navarro 25,000-75,000 ~20% May (2) 2 Liquids-Rich Exploratory Plays Play 1 100, ,000 May Play 2 100, ,000 4Q12 (1) Percentage leased, optioned or under contract compared to midpoint of target acreage range as of (2) Approximately 84,000 net acres leased, optioned or under contract as of

7 Resource Potential Substantial Resource Potential Across Multiple Liquids-Rich Resource Style Plays Wet Gas Transitional Black Oil Utica / Utica / Utica / Woodbine/ Bakken Bakken Mississippi Midway/ TMS Point Pleasant Point Pleasant Point Pleasant Eagle Ford Operated Non-Operated Lime Navarro Net Acres (1) 53,333 53,333 53, , ,000 40,000 15,000 45,000 50,000 Prospectivity of Acreage 70% 70% 70% 70% 70% 90% 70% 50% 50% Prospective Net Acres 37,333 37,333 37, , ,000 36,000 10,500 22,500 25,000 Well Spacing (Acres) Net Drilling Locations Average Net Revenue Interest 81% 82% 82% 76% 75% 80% 80% 80% 78% Gross EUR / Well (Mboe) 1, ,021 Resource Potential (MMBoe) Total Resource Potential of ~1.3 BBoe from extensive multi-year drilling inventory (Wilcox and 2 liquids-rich exploratory plays not included in Resource Potential) (1) Leased, optioned or under contract as of ; TMS and Midway/Navarro net acreage figure is mid-point of target acreage range. Sources: Company and third party estimates. Illustrative assumptions. Note: Utica, Woodbine, TMS, Mississippi Lime and Midway/Navarro EURs are internally generated based upon published industry data. Bakken excludes Three Forks resource potential. EUR estimate based upon available data and may change as more data or our actual drilling and production results becomes available. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs and resource potential. 7

8 Utica/Point Pleasant Overview Utica/Point Pleasant Operating Detail (1) Focus volatile oil and liquids-rich windows Access to cores, geochem and logs NY 3D seismic to optimize completions and reduce costs Intend to let wells rest ~60 days after frac PA Utica/Point Pleasant OH (1)(3) MD Net Acreage (000 s) Targeted Acreage Progress to Target (1) ~80% KY WV VA Operated Rig and Well Estimates 2H12 Rig Count 1-2 2H12 Wells Planned 4 6 Utica/Point Pleasant HK Target Acreage Area (1) Percentage leased, optioned or under contract compared to midpoint of target acreage range as of

9 Utica/Point Pleasant Wet Gas Well Details Type Curve 10,000 1, Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) (Months) Capital Costs / Well ($MM) Total D&C $7.0 Spud to Production (Days) Gross EURs Oil (MBbl) 174 NGL (MBbl) 332 % IRR 100% IRR Sensitivity (1) Spud to Production 120 Average NRI: ~81% Avg. Working Interest ~90% Avg. Revenue Interest ~73% Gas (MMcf) 3,300 Total (MBoe) 1,056 Differentials Oil (% of NYMEX) -$15.00 Gas (% of NYMEX) -$ % 80% 70% 60% 50% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ ($/Bbl NYMEX oil) Note: Internal estimates based on third party data. Company has not completed a well in this play. Individual well results will differ. Type curves are unrisked. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. 9

10 (1) Utica/Point Pleasant Transitional Well Details Type Curve 10,000 1, Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) (Months) Capital Costs / Well ($MM) Total D&C $7.0 Spud to Production (Days) Gross EURs Oil (MBbl) 248 NGL (MBbl) 199 % IRR 100% IRR Sensitivity (2) Spud to Production 120 Average NRI: ~82% Avg. Working Interest ~100% Avg. Revenue Interest ~82% Gas (MMcf) 2,000 Total (MBoe) 780 Differentials Oil (% of NYMEX) -$10.00 Gas (% of NYMEX) -$ % 80% 70% 60% 50% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ ($/Bbl NYMEX oil) Note: Internal estimates based on third party data. Company has not completed a well in this play. Individual well results will differ. Type curves are unrisked. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) Wells along the wet gas/black oil transition zone. (2) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. 10

11 Utica/Point Pleasant Black Oil Well Details Type Curve 1, Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) (Months) Capital Costs / Well ($MM) Total D&C $7.0 Spud to Production (Days) Gross EURs Oil (MBbl) 295 NGL (MBbl) 19 % IRR 60% IRR Sensitivity (1) Spud to Production 120 Average NRI: ~82% Avg. Working Interest ~97% Avg. Revenue Interest ~79% Gas (MMcf) 189 Total (MBoe) 346 Differentials Oil (% of NYMEX) -$4.00 Gas (% of NYMEX) -$ % 40% 30% 20% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ ($/Bbl NYMEX oil) Note: Internal estimates based on third party data. Company has not completed a well in this play. Individual well results will differ. Type curves are unrisked. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. 11

12 Top of Utica Structure Map SEISMIC LINE INVERSION HK PROPOSED WELL EST. SPUD: SEP/OCT 12 HK PROPOSED WELL EST. SPUD: SEP/OCT 12 12

13 Utica/Point Pleasant Rock Properties Rock Properties from Seismic Imaging Lateral Reservoir Boundaries A A POINT PLEASANT PINCH-OUT 13

14 Woodbine/Eagle Ford Overview Woodbine/Eagle Ford Operating Detail Horizontal drilling and modern completion techniques are a game changer Upper Cretaceous section ~40% silica and clastics = deliverability Premium pricing Acreage prospective for Woodbine, Eagle Ford and other formations Covington 1H (Grimes County, TX) Two zone discovery (Woodbine/Eagle Ford) Drilling Woodbine lateral 1, Type Curve (Months) Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) Net Acreage (000 s) Targeted Acreage Progress to Target (1) ~85% Operated Rig and Well Estimates 2H12 Rig Count 4-5 2H12 Wells Planned Capital Costs / Well ($MM) Total D&C $6.0 Gross EURs Oil (MBbl) 396 NGL (MBbl) 36 Gas (MMcf) 253 Total (MBoe) 474 Differentials Oil (% of NYMEX) +2% Gas (% of NYMEX) +2% % IRR 80% 70% 60% 50% 40% IRR Sensitivity (2) Spud to Production (Days) Spud to Production 90 Average NRI: ~76% Avg. Working Interest ~84% Avg. Revenue Interest ~63% 30% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ ($/Bbl NYMEX oil) Note: Internal estimates based on third party data. Individual well results will differ. Type curves are unrisked. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) Percentage leased, optioned or under contract compared to midpoint of target acreage range as of (2) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. 14

15 Woodbine/Eagle Ford Regional Stratigraphic Cross Section Base of Austin Chalk to top of Buda (influence of deltaic sandstone from the north-northeast) HK COVINGTON 1H (not to scale) 15

16 Woodbine Well Performance Operated Well Summary (Gross) # Wells on Production 14 # Wells Flowing Back - # Wells Currently Frac'ing 1 # Wells WOC - # Wells Drilling 2 Total Wells Spud 17 16

17 Tuscaloosa Marine Shale (TMS) Overview Tuscaloosa Marine Shale Operating Detail Oil-prone reservoir in Louisiana and Mississippi Silica-rich shale Age equivalent to the Eagle Ford shale Long-laterals key to well performance Vertical depth of 10,000 to 15,000 feet with laterals as long as 7,250 feet Recent industry results encouraging Premium pricing 10,000 1, Type Curve (Months) Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) Net Acreage (000 s) Targeted Gross EURs Oil (MBbl) 249 IRR Sensitivity (2) Progress to Target (1) ~30% Operated Rig and Well Estimates 2H12 Rig Count 1 2H12 Wells Planned 2-4 Capital Costs / Well ($MM) Total D&C $11.0 Spud to Production (Days) Spud to Production 90 NGL (MBbl) 121 Gas (MMcf) 1,194 Total (MBoe) 569 Differentials Oil (% of NYMEX) +15% Gas ($/Mcf) +$2.50 Average NRI: ~75% Avg. Working Interest ~100% Avg. Revenue Interest ~75% % IRR 20% 15% 10% 5% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ ($/Bbl NYMEX oil) Note: Internal estimates based on third party data. Company has not completed a well in this play. Individual well results will differ. Type curves are unrisked. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) Percentage leased, optioned or under contract compared to midpoint of target acreage range as of (2) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. 17

18 TMS Structure Base HK LAMBRIGHT 1H PTD: 13,500 EST. SPUD: 4Q12 HK BROADWAY 1H PTD: 14,500 EST. SPUD: 3Q12 TMS Penetrations 18

19 TMS Isopach HK LAMBRIGHT 1H PTD: 13,500 EST. SPUD: 4Q12 HK BROADWAY 1H PTD: 14,500 EST. SPUD: 3Q12 TMS Penetrations 19

20 Bakken Overview Bakken Operating Detail NW Williams County (operated) 2 rigs running gross wells planned for 2H12 (~30% ~35% W.I.) Eastern Montana (operated) 1 rig currently running 2 4 gross wells planned for 2H12 (~45% W.I.) Non-operated programs 2 3 rigs running in Mountrail County area (~8% W.I.) 1 rig running in McKenzie Line area (~11% W.I.) Three Forks formation potential Multiple initiatives underway to lower costs and improve recoveries 1, Type Curve (Operated) (Months) Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) Net Acreage (000 s) Targeted Acreage Progress to Target (1) ~60% Operated Rig and Well Estimates 2H12 Rig Count 3 Gross EURs (Operated) Oil (MBbl) 282 NGL (MBbl) 28 Gas (MMcf) 142 Total (MBoe) 333 % IRR 30% 25% IRR Sensitivity (Operated) (2) 2H12 Wells Planned Differentials 20% Capital Costs / Well ($MM) Oil (% of NYMEX) (10.0%) 15% Total D&C $7.5 Gas (% of NYMEX) (11.0%) Spud to Production (Days) Operated Average NRI: ~80% 10% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ Spud to Production 75 Avg. Working Interest ~33% ($/Bbl NYMEX oil) Avg. Revenue Interest ~26% Note: See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) Percentage leased, optioned or under contract compared to midpoint of target acreage range as of (2) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. 20

21 Bakken Position Diversified Footprint Across Bakken Trend 21

22 Operated Bakken Well Performance Operated Well Summary (Gross) # Wells on Production 26 # Wells Flowing Back - # Wells Currently Frac'ing - # Wells WOC 3 # Wells Drilling 3 Total Wells Spud 32 22

23 Mississippi Lime Overview Mississippi Lime Operating Detail Carbonate reservoir (high permeability) Predominantly oil production Shallow drilling depths (2,000 6,000 ) gross thickness Scalability and repeatability Commercial results from offset operators 1, Type Curve (Months) Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) Net Acreage (000 s) Targeted Acreage Progress to Target (1) ~60% Operated Rig and Well Estimates 2H12 Rig Count Wells Planned 8 10 (3) Capital Costs / Well ($MM) Total D&C $3.0 Spud to Production (Days) Gross EURs Oil (MBbl) 113 NGL (MBbl) 30 Gas (MMcf) 204 Total (MBoe) 177 Differentials Oil ($/Bbl) ($4.00) Gas ($/Mcf) ($0.50) Average NRI: ~80% IRR Sensitivity % IRR 30% 25% 20% 15% 10% 5% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ (2) Spud to Production 90 Avg. Working Interest ~100% ($/Bbl NYMEX oil) Avg. Revenue Interest ~80% Note: Internal estimates based on third party data. Company has not completed a well in this play. Individual well results will differ. Type curves are unrisked. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) Percentage leased, optioned or under contract compared to midpoint of target acreage range as of (2) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. (3) Five horizontal well program in progress with the potential to drill eight to ten wells in 2012 depending on results. 23

24 Mississippi Lime Drilling Program Osage County, OK Initial drilling program 5 horizontal wells 4 SWD wells 60 day evaluation period after results from all 5 wells available Additional 16 well locations (plus 6 SWD wells) staked & in process of permitting N 9E N 10E Rock 33Creek 4-9H 34 Spud: Frac: Horizontal Well Bird Creek 2-19H Spud: Est. Frac: Bird Creek 1-19 SWD Spud: N 9E 22 Ricketts 3-35 SWD Spud: Ricketts 4-35H Spud: Frac: Rock Creek 3-9 SWD Spud: N 10E Salt Water Disposal Well PETRA 7/16/2012 1:35:53 PM Est. 33 Frac: Ricketts 5-35H Spud: Strike Axe 4-36 SWD Spud: Strike Axe 5-36H Spud: Frac: FEET ,

25 Midway/Navarro Overview Midway/Navarro Operating Detail Oil prone reservoirs with significant associated high BTU gas and NGLs Premium pricing First well (Kollatschny 1) spud in late May TMD 17,320 Drilling results encouraging (two zone discovery) Five stage Navarro completion underway Second well (Hillboldt 1) spud in late July Net Acreage (000 s) Targeted (1) Gross EURs Oil (MBbl) ,000 1, Type Curve (Months) Gas (Mcf/d) Oil (Bbl/d) NGL (Bbl/d) IRR Sensitivity (1) (3) Progress to Target (2) ~20% Operated Rig and Well Estimates 2H12 Rig Count 1 2H12 Wells Planned 4 6 Capital Costs / Well ($MM) Total D&C $9.0 Spud to Production (Days) Spud to Production 90 NGL (MBbl) 184 Gas (MMcf) 3,920 Total (MBoe) 1,021 Differentials Oil ($/Bbl) ($4.00) Gas ($/Mcf) ($0.50) Average NRI: ~78% Avg. Working Interest 85.0% Avg. Revenue Interest 65.9% % IRR 40% 30% 20% 10% $75.00 $80.00 $85.00 $90.00 $95.00 $ $ $ ($/Bbl NYMEX oil) Note: Internal estimates based on third party data. Individual well results will differ. Type curves are unrisked. See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. (1) EUR and type curve estimates represented on a per zone basis (Midway and Navarro) and are based on early stage internal evaluation. (2) Percentage leased, optioned or under contract compared to midpoint of target acreage range as of (3) Assumes natural gas price of $3.00 / MMBtu and NGL price of 40% of crude oil price. 25

26 Top of Navarro Time Structure Map A HK HILLBOLDT 1 PTD: 15,500 SPUD: HK KOLLATSCHNY 1 TD: 17,320 HK 68 SQ. MI. 3D SURVEY IN-PROGRESS A 26

27 Midway/Navarro Stratigraphic Cross Section 27

28 Liquids-Rich Resource Style Exploratory Plays Targeting 200, ,000 net acres across two unconventional plays Expect to drill in both plays in 2012 Oil and liquids-rich targets Prospect identification driven by technical analysis and experience Due to competitive concerns, additional details not disclosed at this time 28

29 Eagle Ford Overview Eagle Ford Overview To be divested in 2012 HK has been actively drilling in this area for more than a year (18 wells drilled) 12 wells producing 3 wells frac ing 3 wells waiting on completion Two rigs currently running Recent revisions to completion methodology have yielded positive results Net Acreage (000 s) Gross EURs Eagle Ford Acreage Position (2) Current Acreage 24 Oil (MBbl) 300 NGL (MBbl) 24 Operated Rig and Well Estimates 2H12 Rig Count 2 2H12 Wells Planned Capital Costs / Well ($MM) Total D&C $8.5 Spud to Production (Days) Spud to Production 120 Gas (MMcf) 121 Total (MBoe) 344 Differentials Oil (% of NYMEX) -5% Gas (% of NYMEX) -4% Average NRI: ~82% Avg. Working Interest ~45% Avg. Revenue Interest ~37% Note: See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of EURs. 29

30 Avg. Daily Production Rate - Oil Only (Bbl/d) Eagle Ford Project Improvements First three well completions largely ineffective Laterals with frac stages 40/70 white sand (embedment issues) Slick water, linear gels and cross link frac fluids Recent 9 wells Targeting laterals with 20 frac stages 20/40 and 30/50 resin coated and white sand Cross link gel Six still flowing up 5.5 frac string Performing significantly above 344 Mboe type curve Average Eagle Ford Daily Oil Production Rates Type Curve First 3 Wells 200 Recent 9 Wells Day Rate 30 Day Rate 45 Day Rate 60 Day Rate 90 Days 30

31 Hedging Summary as of Plan to hedge 80% of expected production over month period Recently amended revolving credit facility terms to allow hedging of up to 85% of expected production Oil Hedge Summary 2H 2012 FY 2013 FY 2014 Volume (Bbls) Ceiling / Swap Price (1) Floor Purchased (1) Floor Sold (1) Volume (Bbls) Ceiling / Swap Price (1) Floor Purchased (1) Floor Sold (1) Volume (Bbls) Ceiling / Swap Price (1) Floor Purchased (1) Floor Sold (1) Three-Way Collars 218,500 $ $93.11 $ ,075 $ $95.18 $ ,500 $99.59 $95.00 $70.00 Collars 452,300 $ $ ,810,875 $95.73 $ Swaps 330,000 $ ,000 $ Total (Bbls) 1,000,800 2,421, ,500 Total (Bbls/d) 5,439 6, % Production Hedged (2) NA 32% NA Wtd. Avg. Price ($/Bbl) (3) $92.58 $89.30 $95.00 Gas Hedge Summary 2H 2012 FY 2013 FY 2014 Volume Ceiling / Floor Floor Volume Ceiling / Floor Floor Volume Ceiling / Floor Floor (MMBtu) Swap Price (1) Purchased (1) Sold (1) (MMBtu) Swap Price (1) Purchased (1) Sold (1) (MMBtu) Swap Price (1) Purchased (1) Sold (1) Collars 460,000 $6.00 $ Swaps 870,000 $ ,000 $ Total (Mcf) 1,330, ,000 0 Total (Mcf/d) 7,228 1,274 0 % Production Hedged (2) NA 13% NA Wtd. Avg. Price ($/Bbl) (3) $4.74 $4.18 NA Combined Oil and Gas Hedge Summary 2H 2012 FY 2013 FY 2014 Total Hedged (Boe) 1,222,467 2,499, ,500 Total Hedged (Boe/d) 6,644 6, % Production Hedged (2) NA 20% NA (1) Weighted averaged price (2) Based on midpoint of production guidance. (3) Based on floors purchased for collars and 3 way collars 31

32 Pro Forma Capitalization and Liquidity ($ in millions) As of June 30, 2012 High Yield Halcon Acquisition Offering Halcon Actual Adjustments (1) Adjustments Pro Forma Cash and Equivalents $219.2 ($868.7) $724.8 $75.4 Long-Term Debt Revolving Credit Facility New Senior Unsecured Notes % Senior Unsecured Convertible Notes (2) $242.6 $0.0 $0.0 $242.6 Total Long-Term Debt $242.6 $0.0 $739.8 $982.4 Total Net Debt $23.4 $868.7 $15.0 $907.1 Liquidity Revolving Credit Facility Borrowing Base $225.0 $525.0 Less: Amount Drawn - - Cash on Hand Liquidity $444.2 $600.4 $600 million in liquidity in addition to future cash flow and proceeds from divestitures (Eagle Ford) provides ample liquidity to fund 12 & 13 capital programs 12 & 13 capital programs are largely discretionary and can be scaled up or down depending on market conditions, drilling results and capital availability (1) Acquisition adjustments include the GeoResources and East Texas Assets acquisitions. The GeoResources transaction consisted of $591.2 MM in cash consideration (including $20.0 million in estimated fees & expenses and the repayment of GeoResources net debt balance of $39.7 million) and the issuance of 51.3 MM of HK shares. The East Texas Assets acquisition consisted of $302.2 MM in cash consideration ($24.8 MM of which was paid prior to ) and the issuance of 20.8 MM of HK shares. (2) $275 MM convertible debt is shown net of a $41.3 MM unamortized discount and approximately $8.9 MM of interest that was paid in kind. 32

33 Operating and Financial Guidance Summary Production Total (Boe/d) 4,055 3,912 1Q12A 2Q12A 3Q12E (1) 4Q12E 2012E 2013E Low High 11,000 13,000 17,000 20,000 9,000 11,000 32,000 38,000 % Oil 61% 62% 60% 60% % NGLs 11% 11% 15% 15% % Gas 28% 27% 25% 25% Operating costs and expenses Lease Operating ($ / Boe) Production Taxes ($ / Boe) Cash G&A ($ / Boe) Low High Low High Low High $11.00 $15.00 $4.00 $5.00 $10.00 $13.00 $5.00 $7.00 $4.00 $5.00 $4.00 $6.00 Capex Excluding Acquisitions and Divestitures ($ in Bn) (2) $1.1 $1.1 % Drilling and Completion 35% 75% Note: Guidance is provided on an SEC accounting basis and is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company s control. See Forward-Looking Statements on page 2. (1) GeoResources and East Texas Assets acquisitions closed (2) Does not include the cash consideration of the GeoResources and East Texas Assets acquisitions or the acquisition of 27,000 net acres of oil and gas leasehold in Ohio. 33

34 2012 Capital Budget Breakdown By Category SEC Accounting Basis Pro Forma Basis Leasehold Acquisitions ~55% ~50% Drilling & Completions ~35% ~40% Infrastructure and Other ~10% ~10% Total ~$1.1 Bn ~$1.2 Bn D&C By Area SEC Accounting Basis Pro Forma Basis Utica/Point Pleasant ~10% ~7% Woodbine/Eagle Ford ~24% ~20% TMS ~9% ~7% Bakken ~13% ~23% Mississippi Lime ~3% ~2% Wilcox ~8% ~7% Midway/Navarro ~10% 7% Exploratory Plays ~5% ~3% Other (1) ~19% ~24% Total ~$375 MM ~$480 MM Note: Capital budget subject to revision. (1) Includes Eagle Ford properties in Fayette and Gonzales Counties, Texas, which will be divested. 34

35 HK Investment Highlights Proven Management Team With Significant Ownership Stake Technical Bias With Extensive Resource Style Play Experience Attractive Liquids-Rich Asset Portfolio With Compelling Economics Positioned For Significant Near-Term Reserve And Production Growth Substantial Resource Potential Across Multiple Liquids-Rich Resource Style Plays Excellent Track Record For Managing Cash Margin The Best Hedge Solid Balance Sheet And Liquidity To Fund Growth Note: See Cautionary Statement Regarding Hydrocarbon Quantities on page 3 for a description of resource potential and EURs. 35

36 Appendix

37 Pro Forma Production and Reserves (74% Liquids) Avg. Net Daily Production (Boe/d) (1) Proved Reserves (2) 1Q12 2Q12 Variance Q/Q Oil MBbls Gas MMcf NGL MBbls Equiv. Mboe % Oil/NGLs % PD % Total Reserves PV10 (2) ($MM) % Total PV10 RESOURCE STYLE North Dakota/Montana Bakken 2,305 2,714 18% 6,264 3, ,044 93% 59% 10% $ % Texas Austin Chalk 2,642 2,467-7% 1,167 39,498 1,262 9,012 27% 64% 12% $ % Eagle Ford % ,017 94% 17% 1% $16.4 1% Woodbine/Eagle Ford 1,597 2,353 47% 15,777 9,488 1,691 19,049 92% 18% 26% $ % 4,501 5,462 21% 17,834 49,335 3,022 29,079 72% 32% 40% $ % TOTAL RESOURCE STYLE 6,806 8,176 20% 24,098 52,375 3,295 36,122 76% 37% 50% $ % CONVENTIONAL Lousiana 1,360 1,371 1% 3,725 14,499-6,141 61% 70% 8% $ % North Dakota/Montana % 4,585 1,087-4,766 96% 73% 7% $96.6 6% Oklahoma Fitts-Allen % 4,916 1, ,235 95% 74% 7% $ % Other % 482 7, ,791 28% 70% 2% $21.5 1% 1,173 1,132-3% 5,399 9, ,026 78% 73% 10% $ % Texas Electra/Burkburnett 1,356 1,349-1% 5, , % 65% 9% $ % La Copita % ,204 1,263 4,936 32% 30% 7% $46.4 3% Permian (3) % 1,205 2, ,597 78% 72% 2% $46.3 3% Other 1,090 1,080-1% 1,801 9, ,607 58% 94% 5% $65.5 4% 3,477 3,315-5% 9,201 31,485 1,909 16,358 68% 62% 22% $ % Other States % 1,470 4, ,356 70% 82% 3% $50.8 3% TOTAL CONVENTIONAL 6,665 6,686 0% 24,380 60,532 2,179 36,647 72% 68% 50% $ % TOTAL COMPANY 13,471 14,862 10% 48, ,907 5,474 72,769 74% 53% 100% $1, % Variance vs. HK Stand-Alone 232% 279% 292% 182% 172% 246% 6% -8% 302% (1) Includes GeoResources (including Austin Chalk acquisitions in 1Q12) and East Texas Assets acquisitions. (2) Proved reserves and PV10 pro forma for GeoResources and East Texas Assets acquisitions. Pro forma proved reserves data consist of (i) proved reserves for Halcón as of , as estimated by Halcón s independent reserve engineers, (ii) proved reserves of GeoResources as of as estimated by GeoResources independent reserve engineers (except for certain Austin Chalk reserves acquired in 1Q12, which were estimated by GeoResources internal reserve engineers) and (iii) proved reserves attributable to the East Texas Assets as of , as estimated by Halcón s internal reserve engineers using unweighted average first-day-of-the-month commodity prices for the year ended and otherwise in accordance with SEC rules relating to reporting of reserves. (3) Includes approximately 897 Mboe of reserves located in New Mexico. 37

38 Pro Forma Proved Reserves Overview Pro forma proved reserve base is liquids-rich (geographically and by basin) diversified, with an attractive PDP / PUD mix Highly Diversified Pro Forma Proved Reserves of 72.8 MMBoe 74% of Pro Forma Proved Reserves Are Liquids (Oil/NGLs) Fitts-Allen South Lousiana 7% 8% Electra / Burkburnett 9% Woodbine / Eagle Ford 27% Gas 26% Bakken 10% NGLs 8% Oil 66% Other 39% Proved Reserves Split Between Resource and Conventional 55% of Pro Forma Proved Reserves Are Proved Developed Conventional 50% Resource 50% Proved Undeveloped 45% Proved Developed 55% Total Pro Forma Proved Reserves: 72.8 MMBoe (1) Proved reserves pro forma for GeoResources Merger and the acquisition of the East Texas Assets. Pro forma proved reserves data consists of (i) proved reserves for Halcón as of , as estimated by Halcón s independent reserve engineers, (ii) proved reserves of GeoResources as of as estimated by GeoResources independent reserve engineers (except for certain Austin Chalk reserves acquired in the first quarter of 2012, which were estimated by GeoResources internal reserve engineers) and (iii) proved reserves attributable to the East Texas Assets as of , as estimated by Halcón s internal reserve engineers using unweighted average first-day-of-the-month commodity prices for the year ended and otherwise in accordance with SEC rules relating to reporting of reserves. (1) 38

39 Halcón History (1) Recapitalized RAM Energy Resources, Inc. Funded with $550 million investment by EnCap, Liberty Energy Holdings, Mansefeldt Investment Corp., and Halcón Management Replaced management and board 21.1 MMBoe proved reserves as of MBoe/d production (2Q12) Raised $400 million of equity through PIPE offering Moved listing to NYSE and changed ticker to HK Closed the acquisition of 27,000 net acres in Ohio prospective for the Utica Shale for $164 million February 2012 March 2012 April 2012 May 2012 June 2012 July 2012 August 2012 Closed new revolving credit facility $500 million facility with initial borrowing base of $225 million Announced one-for-three (1:3) reverse stock split Raised $750 million of HY debt Closed the East Texas Assets acquisition Funded with ~$300 million of cash and ~20.7 million shares of equity Will add proved reserves of ~19 MMBoe and 2Q12 avg. daily production of ~2.3 MBoe/d (2) Closed the acquisition of GeoResources, Inc. Consideration funded with $20.00 in cash and Halcón shares per GEOI share (approximately 50% cash / 50% stock) Added proved reserves of ~33 MMBoe as of and 2Q12 production of ~8.6MBoe/d (3) Borrowing base increased to $525 million (1) Comprised of $790 million of equity for acquisitions, $275 million of common equity from recapitalization, $400 million of common equity from the PIPE, and $275 million of convertible debt with a conversion price of $4.50 per share. The convertible debt is in the money ( closing share price of $10.95). (2) Proved reserves based on Halcón internal estimates as of using unweighted average first-day-of-the-month prices for the year ended and otherwise in accordance with SEC rules relation to reporting of reserves. (3) Includes Austin Chalk estimated proved reserves and production acquired in the first quarter of 2012; the reserves were estimated by GeoResources internal reserve engineers as of

40 HK Ownership HALRES LLC, Comprised of HK Management and Seasoned Energy-Focused Private Equity Firms, Have Substantial Equity Stakes Owner Basic Percent Ownership Warrants Convertible Debt (1) Options Fully Diluted Percent Ownership Net Diluted Percent Ownership HALRES LLC (2) % 36.7 (3) % % Public Shareholders % % % GeoResources Shareholders (4) % % % East Texas Assets Shareholders (5) % % % Employee Options (6) - 0% % 0.2 0% Shares Outstanding % % % (1) Not convertible into common shares until at $4.50/share. (2) Includes EnCap Investments L.P., Liberty Energy Holdings LLC, Mansefeldt Investment Corp and members of the Halcón management team. A management led group owns approximately 10% of HALRES LLC (formerly Halcón Resources LLC). (3) Exercisable at $4.50/share (4) Common shares issued in conjunction with GeoResources, Inc. acquisition. (5) Common shares issued in conjunction with the East Texas Assets (Woodbine) acquisition. (6) Employee Options as of

41 Contact: Scott Zuehlke, VP - Investor Relations 1000 Louisiana St., Suite 6700, Houston, TX szuehlke@halconresources.com