Halcón Resources Investor Presentation June 19, 2018

Transcription

1 Halcón Resources Investor Presentation June 19, 2018

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. Forward looking statements often, but not always, can be identified by words such as "expects", "anticipates", "plans", guidance, "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 reserves involved can be economically exploited. Statements regarding pending acquisitions and possible dispositions are forward looking statements; there can be no guarantee that acquisitions or dispositions close on the terms or within the timeframe described, if at all. 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 our 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' operations or financial results are included in Halcón Resources reports on file 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 those expressed in 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 assumptions, estimates or opinions change.

3 Cautionary Statements 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. These estimates are by their nature more speculative than estimates of proved reserves and are subject to greater uncertainties and, accordingly, the likelihood of recovering those reserves is subject to substantially greater risks. We 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 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 and are subject to substantially greater uncertainties relating to recovery than reserves. 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 estimated by well spacing assumptions applicable to that area. The actual number of 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 the drilling locations which have been attributed to any area. We may use the term de risked in this presentation to refer to certain acreage and well locations where we believe the relative geological risks related to recovery have been reduced as a result of drilling operations to date. However, only a small portion of such acreage and locations may have been attributed proved undeveloped reserves and ultimate recovery from such acreage and locations remains subject to all of the recovery risks applicable to unproved acreage. Factors affecting ultimate recovery include: (1) the scope of our on going drilling program, which will be directly affected by factors that include 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 (2) actual drilling results, including geological and mechanical factors affecting recovery rates. 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 will be affected by changes in commodity prices and costs.

4 Halcón Resources Overview Halcón has built a premier ~60,000 acre position in the Delaware Basin for less than $19,000/net acre (1) Delaware Basin Overview Total Company Acreage Position Monument Draw (Ward County) Net Acreage: ~22,479 with ~97% average W.I. 505 gross potential operated drilling locations Wolfcamp EURs of ~1.9 MMBoe (~80% oil) assuming 10K laterals West Quito Draw (Ward County) Net Acreage: ~10,622 with ~72% average W.I. 407 gross potential operated drilling locations Wolfcamp EURs of ~2.2 MMBoe (~50% oil) assuming 10K laterals West Quito Draw Monument Draw Hackberry Draw (Pecos County) Net Acreage: ~27,115 with ~74% average W.I. 1,143 gross potential operated drilling locations Wolfcamp EURs of ~1.5 MMBoe (~75% oil) assuming 10K laterals Total Company: Net Acreage: ~60,216 Operated Potential Gross Drilling Locations: 2,055 Current Production: >13,500 Net Boe/d Hackberry Draw Note: See Cautionary Statements on page 3 for a discussion on risks associated with drilling locations and EURs. (1) Values production acquired at $35,000 per boe/d; assumes $59 MM of value attributed to infrastructure assets purchased in Hackberry Draw. 4

5 Issues of Focus for Investors Issue Cash Flow and Liquidity MidCush Basis Differential Oil Takeaway Well Costs HK Response > $380 MM of current pro forma liquidity Borrowing base recently increased by $100 MM and expect further increase in fall > $150 MM of liquidity in all future periods until free cash flow positive status achieved (based on internal forecasting) Potential infrastructure monetization further enhances liquidity (also value accretive) 2Q 18: 8,000 Bbl/d hedged at $1.27 2H 18: 8,000 Bbl/d currently hedged at $ Recently monetized swaps to realize $7.79/Bbl in value = Effective Discount of $3.90 on 8,000 Bbl/d 1H 19: 12,000 Bbl/d currently hedged at $ Recently monetized swaps to realize $3.05/Bbl in value = Effective Premium of $0.03 on 12,000 Bbl/d Near term: 85%+ of oil on pipe in next few months (Modest discount to Midland) Longer term: Expect to sign agreement for 25,000 Bbl/d of firm capacity on pipeline to Gulf Coast to be in service by 2H 19 (Premium to WTI) Completion costs are moderating Significant opportunities to reduce costs as we gain scale (pads, local sand, etc.) Future Acquisitions No need or desire to significantly grow footprint with 2,000+ operated locations Only focused on small bolt on opportunities or swaps to firm up units for long laterals 5

6 Why HK is a Compelling Investment Opportunity HK Trades at Significant Discount to Peers Adjusted TEV (1) /2019 EBITDA Price / 2019 CFPS 6.4x 6.2x 6.1x 6.0x 5.5x 5.2x 4.6x 5.7x 5.5x 5.4x 4.8x 4.6x 3.6x 2.2x FANG PE CDEV JAG EGN CPE HK FANG CDEV PE JAG EGN CPE HK Implied Value per Acre (2) $51,329 $42,839 $33,866 $31,548 $26,766 $26,704 $8,654 FANG CDEV PE CPE EGN JAG HK (1) Adjusted TEV calculated as current market cap as of 6/12/18 plus projected net debt at 12/31/19 based on consensus forecasts. (2) Calculated as current enterprise value less value of current production at $35K/boed. HK value also adjusted for $150 MM related to invested cost in infrastructure assets to date. 6

7 2 nd Half 2018 Plan Focused on Development, Delineation & Gaining Scale 2018 Plan Highlights Reduced Rig Plan Recently decided to drop a rig given weaker recent Midland pricing 3 operated rigs running for the 2 nd half of 2018 Combination of Development & Delineation Drilling Long lateral development (9,500+ ft.) Transitioning to multi well pad development Testing upside pay zones (BS, deep targets, etc.) Optimal spacing tests Vertical pilot wells Shuttle logs to determine optimal geo steering and frac design Focus on Efficiencies Focus on reducing drilling days Beginning to utilize some local brown sand (i.e. 100 mesh) Utilize new technologies & techniques to optimize completions Production Optimization Installation of jet pumps for artificial lift Removing production bottlenecks Focus on reducing downtime through proactive maintenance program $58.00 $56.00 $54.00 $52.00 $50.00 $48.00 $46.00 Midland Basis $/Bbl $2.00 $0.00 ($2.00) ($4.00) ($6.00) ($8.00) ($10.00) ($12.00) ($14.00) ($16.00) 2H 2018 Midland Prices ($/Bbl) $ H 18 Midland prices have declined almost $6.00/bbl in less than 3 months $50.75 March 15, 2018 Current (June 15, 2018) Forward Midland/WTI Differentials ($/Bbl) MidCush basis differentials have recently blown out to >$12/Bbl for 2H 18 through mid 19 ($18.00) Jan 18 Jul 18 Jan 19 Jul 19 Jan 20 Jul 20 Jan 21 January 2018 Strip April 2018 Strip June 2018 Strip 7

8 Focus on Long Lateral Development Halcón is focused on drilling long laterals in all areas in 2018 Near term impact: Longer cycle times Less capital efficient in 1 st few months Long term impact: More capital efficient Lower PDP decline rates Better returns More valuable assets/company Average Completed Lateral Length (CLL) 12,000 10,000 9,567 8,853 Avg. CLL (2H '17 1Q '18) (1) Peer Avg: 7,375 ft. 8,000 8,053 7,887 7,786 7,310 6,000 5,996 5,741 4,000 2,000 HK Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Economic benefits of 10K vs. 5K ft. lateral: 1 st 5 Years Production: 10K lateral: > 800K Boe 5K lateral: ~400K boe PV10 (2) : 10K lateral: $15 MM 5K lateral: $3 MM IRR (2) : 10K lateral: 68% 5K lateral: 28% Production Profile Comparison: 10,000 vs. 5,000 2 phase Cumulative Production (boe) 1,000, , , , ,000 0 Monument Draw Wolfcamp Lateral Productivity Months on Production 10K Lateral Doubles Production in First 5 Years of Well Life Note: See Cautionary Statements on page 3 for a discussion on risks associated with drilling locations and EURs. (1) Represents wells POL in Pecos and Ward Counties from July 2017 to March Peers include Energen, Callon, Diamondback, Jagged Peak, Parsley, Centennial and RSP Permian. (2) Based on HK s Monument Draw type curve using 4/12/18 strip pricing. 5k lateral 10k lateral 8

9 Well Situated with Takeaway and Protected from Basis Blowout Oil Takeaway Near Term Oil Takeaway: >85% of HK s oil production is currently on pipe or will be on pipe by Q Pricing of Midland less $0.50 to $1.25/bbl Very little trucked = lower risk of getting oil to market at good prices Long Term Oil Takeaway: In advanced negotiations for an agreement to get 25,000 bbl/d of firm space on pipeline to Gulf Coast (expected 2H 2019) Pricing likely apremium to NYMEX Effective HK Midland Pricing 2H 18 ($/Bbl) Gas Takeaway Primary Plan L T firm commitment contracts in all areas for third party midstream operators to take high pressure wet gas to their processing plants Pricing of WAHA flat to WAHA less $0.03/Mmbtu Contingency Plan Multiple low pressure back up sales points available should primary takeaway option be unavailable (i.e. force majure) Basis Hedges in Place Mid Cush Hedges Currently in Place: 2H 18: 8,000 bbl/d at $ H 19: 12,000 bbl/d at $ 3.02 April 2018 Mid Cush Hedge Monetization: Realized ~$30 MM in cash proceeds $7.79/bbl in value for 2H 18 hedges $3.05/bbl in value for 2019 hedged WAHA Basis Hedges Currently in Place: 15,000 Mmbtu/d for 2H 18 at $ ,500 Mmbtu/d for 2019 at $ 1.18 Effective HK Midland Pricing 1H 19 ($/Bbl) On 8,000 bopd of hedged production for 2H 18 HK is effectively receiving a $9.60/bbl premium to current Midland pricing On 12,000 bopd of hedged production for 1H 19 HK is effectively receiving a $11.46/bbl premium to current Midland pricing (1) (2) $64.25 $11.69 $7.79 $60.35 $50.75 $9.60 $62.56 $3.02 $3.05 $62.59 $51.13 $11.46 Current WTI Price Avg. Price of HK MidCush Differentials Currently in Place HK Proceeds Received from April '18 Monetization Effective 2H '18 Realized HK Pricing Current Midland Pricing HK Effective Premium to Midland Pricing Current WTI Price Avg. Price of HK MidCush Differentials Currently in Place HK Proceeds Received from April '18 Monetization Effective 2H '18 Realized HK Pricing Current Midland Pricing (1) (1) (1) (1) (2) (2) HK is well positioned through 1H 19 with strong takeaway contracts in place and significant basis hedged Note: See further detail of takeaway contracts on slide 18. Does not include impact of NYMEX oil and gas hedges in place. 1. Strip pricing as of 6/15/ Calculated as ~$30 MM in hedge monetization proceeds related to hedges monetized in April 2018 divided by monetized mid cush hedge volumes for each time period. HK Effective Premium to Midland Pricing 9

10 Wolfcamp Type Curves 10,000 Lateral Normalized Rate (Boe/d) 2,000 1,500 1, Normalized Time (Months) Monument Draw (2 Stream) (1) D&C: ~$12.5 MM 2 Stream EUR: 1.9 Mmboe (80% Oil, 20% Gas) 2 Stream 30 Day Peak IP: ~1,434 boe/d PV 10 ($MM) $30.0 $20.0 $10.0 $0.0 $7.3 31% $ % $ % $ % $40 $50 $60 $70 NYMEX Oil ($/bbl) WC PV 10 WC IRR 240% 200% 160% 120% 80% 40% 0% IRR (%) Normalized Rate (Boe/d) Normalized Rate (Boe/d) 2,500 2,000 1,500 1,000 1, Normalized Time (Months) Normalized Time (Months) Note: See Cautionary Statements on page 3 for a discussion on risks associated with EURs. (1) Assumes a $3.00/MMBtu gas price and NGL pricing of ~38% of NYMEX oil and current D&C costs. West Quito Draw (2 Stream) (1) D&C: ~$11.5 MM 2 Stream EUR : 2.2 Mmboe (50% Oil, 50% Gas) 2 Stream 30 Day Peak IP: 2,089 boe/d Hackberry Draw (2 Stream (1) D&C: ~$11.0 MM 2 Stream EUR: 1.5 Mmboe (75% Oil, 25% Gas) 2 Stream 30 Day Peak IP: 942 boe/d PV 10 ($MM) PV 10 ($MM) $30.0 $22.5 $15.0 $7.5 $0.0 $30.0 $20.0 $10.0 $0.0 $16.3 $11.8 $7.3 $2.7 82% 18% 35% 56% $40 $50 $60 $70 NYMEX Oil ($/bbl) WC PV 10 $16.7 $12.2 $7.7 $3.2 72% 19% 51% 34% $40 $50 $60 $70 NYMEX Oil ($/bbl) WC PV 10 WC IRR WC IRR 240% 180% 120% 60% 0% 240% 200% 160% 120% 80% 40% 0% IRR (%) IRR (%) 10

11 Monument Draw WC Performance vs. Type Curve Note: See Cautionary Statements on page 3 for a discussion on risks associated with EURs. Monument Wolfcamp Type Curve (1.9 Mmboe EUR) Offset Operator Wells HK Drilled and Completed Wells 11

12 Hackberry Draw WC Performance vs. Type Curve Legacy wells underperformed type curve from ~50 to ~300 days due to timeliness of artificial lift installations and inefficient gas lift design Hackberry Wolfcamp Type Curve (1.5 Mmboe EUR) Legacy Operator Wells HK Drilled and Completed Wells Note: See Cautionary Statements on page 3 for a discussion on risks associated with EURs. 12

13 First Year Cumulative Oil Production Wolfcamp 419, , , , , ,339 Monument Draw WC West Quito Draw WC Hackberry Draw WC Oil (Bbls) Combined (Boe) West Quito Draw s Projected First Year Cumulative Oil is Prolific. Natural Gas and NGLs will Add to Profitability of Drilling Here Note: See Cautionary Statements on page 3 for a discussion on risks associated with EURs. Based on 2 stream production and no downtime. 13

14 Multiple Targets Across All Acreage Monument Draw Type Log West Quito Draw Type Log Hackberry Draw Type Log 3,600 1 st & 2 nd BS Shale Top Seal 3,520 2,630 3 rd BS Shale 3 rd BS Sand Deep Woodford Base Case Target (Already De Risked) Upside Target (To Be De Risked) Deep Wolfcamp Sands Note: See Cautionary Statements on page 3 for a discussion on risks associated with drilling locations and EURs and the meaning of de risked. 14

15 Decades of Drilling Inventory Gross Remaining Operated Locations (1) De risked base case drilling inventory Additional targets , , WC Zones (Monument) Gross Locations 1, rd BS (Monument) WC Zones (Hackberry) Locations by Area Net Locations Monument Draw Hackberry Draw West Quito Draw Note: See Cautionary Statements on page 3 for a discussion on risks associated with drilling locations and the meaning of de risked. (1) Gross Operated Locations per Halcón s internal estimates. (2) Assumes a rig can drill 12 wells per year rd BS (Hackberry) WC Zones (West Quito) BS (West Quito) 55 Total Base Case Locations Inventory Length (Years) (2) Years Inventory 41 Additional Locations (Monument, Hackberry & West Quito) Operated Rigs Running 27 Total Potential Locations 24 15

16 Halcón Field Services Cost Benefits of HK Owned Water Infrastructure Infrastructure Map $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 $0.45 $0.18 Water Sourcing Costs ($/Bbl) HK Owned $1.00 $0.40 Water Disposal Costs ($/Bbl) 3rd Party Area Surface Acreage Held (1) Water Pipelines in Place (1) Produced Water Capacity (1) Fresh Water Capacity (1) Water Storage Capacity (1) Gas Gathering, Compression & Treating (1) Monument Draw 1,625 acres 27 miles 20,000 bwpd of injection (3 wells) 40,000 bwpd of recycling (1 facility) 10 wells with 60,000 bwpd of capacity Additional capacity available 900,000 bbls of produced/recycled water 1,100,000 bbls of fresh water storage 22 miles of steel pipe 5 MMSCFD Gas sweetening, dehy and JT unit West Quito Draw Acquiring surface now Construction beginning shortly Planning SWD wells now Planning fresh water wells now Construction beginning shortly Handled by Crestwood Hackberry Draw 3,243 acres 23 miles 45,000 bwpd of injection (3 wells) 120,000 bw/d of recycling (3 facilities) 4 wells with 40,000 bwpd of capacity Additional capacity available 2,700,000 bbls of produced/recycled water storage 1,000,000 bbls of fresh water storage 28 miles of steel/poly pipe 12 MMSCFD Gas sweetening & dehy and JT unit (1) As of 3/31/18. 16

17 Halcón Field Services Water Handling and Recycling Continuing to develop produced water recycling and injection capabilities throughout each asset (see previous slide) Water Handling Capacity vs. Forecast (1) Maintaining capacity above forecasted volumes critical for potential downtime associated with maintenance or workovers on midstream facilities Critical for LOE/GTO cost control Apr 18 Jun 18 Aug 18 Oct 18 Dec 18 Feb 19 Apr 19 Jun 19 Aug 19 Oct 19 Dec 19 Feb 20 Apr 20 Jun 20 Aug 20 Oct 20 Dec 20 Feb 21 Apr 21 Jun 21 Aug 21 Oct 21 Dec 21 Feb 22 Apr 22 Jun 22 Aug 22 Oct 22 Dec 22 Water Injection Capacity Water Recycling Capacity Water Forecast Water Recycling vs. Frac Water Needs (1)(2) Since start of operations in Delaware, ~70% of water used for completions (~5 MM bbls) has been sourced from our recycling facilities At least 75% of water used for completions in 2018 will be recycled Goal is to be at or near 100% by start of 2019 Simplifies and expedites water sourcing for our completion schedule Critical for capex cost control (saves ~30 40% vs. sourcing water from 3 rd parties) Recycled Water Available for Use Recycled Water Demand for Frac's (1) Based on most recent production forecasts and midstream facility build outs for Monument Draw, Hackberry Draw, and West Quito Draw. (2) Chart assumes % of water utilized for each frac is recycled; use of recycled water will vary by asset depending on availability of recycled water, frac design, and pad size. 17

18 Oil & Gas Marketing & Takeaway Monument Draw West Quito Draw Hackberry Draw Current: Current: Current: Oil Marketing & Takeaway All oil sold via truck to single buyer Pricing: Midland less ~$4.00/bbl Projected Sept. 18: All oil taken to Wink via pipeline constructed by 3 rd party midstream company Pricing: Modest discount to Midland Mid 2019: Expect to sign agreement for firm space to Gulf Coast on new pipeline (20K bbl/d) with flexibility to scale up or down over time Realized pricing likely at premium to Midland All oil sold via truck to single buyer Pricing: Midland less ~$3.25/bbl Projected Q4 18: All oil taken to Wink via pipeline constructed by 3 rd party midstream operator Pricing: Modest discount to Midland Mid 2019: Expect to sign agreement for firm space to Gulf Coast on new pipeline (5K bbl/d) Realized pricing likely at premium to Midland ~70% sold via pipeline and remainder trucked; All sold to Sunoco under adeal that expires in August 2019 Pricing: Midland less ~$1.25/bbl By Q4 18, expect 75% to be sold via pipeline Aug. 19: Current gathering deal expires in Aug. 19 Negotiating w/ several midstream companies to provide oil takeaway options including long haul optionality Realized pricing likely at premium to Midland Gas Marketing & Takeaway Primary Plan: Contract in place through 2032 with 3 rd party midstream operator to take wet gas to their processing plant via high pressure pipeline Multiple sales outlets from tailgate of plant (El Paso, Comanche Trail and Roadrunner) Firm commitment in place to take and sell our gas Pricing: WAHA flat Back up Plan: Multiple low and high pressure sales points with ETC Primary Plan: Contract in place with Crestwood through 2036 to gather and compress gas from wellhead High pressure wet gas will be delivered to 3 rd party midstream operator and taken to their processing plant under same terms as Monument Draw (i.e. firm commitment) Pricing: WAHA flat Back up Plan: Crestwood has several other outlets to move gas to various plants in the Delaware Basin Primary Plan: Contract in place through 2027 with ETC to take wet gas to their Arrowhead processing plant via high pressure line All pipes at WAHA available under this deal HK has firm capacity that is expandable Pricing: WAHA less ~$.03/Mmbtu Back up Plan: Multiple low pressure sales points with ETC Another 3 rd party midstream operator will have high pressure sales connection by late 2018 HK Has Contracts in Place to Handle All Projected Oil and Gas Production with No MVCs 18

19 Pro Forma Capitalization Simple capital structure No near term debt maturities Strong liquidity Highlights $380 MM PF West Quito Draw acquisition Halcón has significant liquidity to fund its planned operations Pro Forma Capitalization West Pro Forma Face Value Actual Quito Draw Adjusted HK Capitalization ($MM) 3/31/2018 Acquisition 3/31/2018 Cash & Cash Equivalents $ 382 $ (200) $ 182 Senior Secured Revolving Credit Facility 6.75% Senior Unsecured Notes due Total Debt $ 625 $ 625 Total Net Debt / (Cash) $ 243 $ 443 Stockholders' Equity 1,134 1,134 Total Capitalization $ 1,759 $ 1,759 Borrowing Base (1) $ 200 $ 200 Less: Borrowings Less: Letters of Credit (2) (2) Plus: Cash Total Liquidity $ 580 $ 380 (1) Borrowing base reflects borrowing base adjusted for Spring 2018 redetermination effective May 1,

20 Investment Highlights Significant Inventory ~60,000 net acres in the oily window of the Delaware Basin (70% oil) Over 2,000 gross operated locations with an average lateral length of ~9,500 ft. Manageable HBP requirements Excellent Growth Profile Q4 17 to Q4 18 expected production growth in excess of 300% Significant long term growth potential Strong Balance Sheet Strong current liquidity of ~$380 MM Reasonable leverage profile No near term debt maturities Compelling Return Profile Well level IRRs of 50% to 100% at current strip Strong corporate level returns Attractive Valuation Halcón trades at a significant discount to most peers on a variety of metrics (i.e. TEV/EBITDA, Implied value per acre, etc.) Halcón's average purchase price of less than $19K/acre is significantly below the average price of other Delaware Basin transactions Committed and Experienced Team Management has significant equity stake in company Technologically focused operations group Decades of value creation experience through M&A&D and shale development 20

21 Appendix

22 Commodity Hedges 25,000 20,000 15,000 10,000 5,000 NYMEX WTI Costless Collars $56.26 $55.98 $56.87 $56.42 $59.37 $53.17 $49.01 $48.96 $50.08 $ ,504 13,000 9,000 10,000 10,673 Q2 '18 Q3 '18 Q4 '18 Q2'18 Q4'18 FY 2019 Hedged Volume (Bbl/d) Average Floor ($/bbl) Average Ceiling ($/bbl) $65.00 $60.00 $55.00 $50.00 $45.00 $40.00 $35.00 $30.00 $ ,000 30,000 25,000 20,000 15,000 10,000 5,000 NYMEX Gas Costless Collars $3.30 $3.30 $3.30 $3.30 $3.01 $3.01 $3.01 $3.01 $3.01 $ ,000 7,500 7,500 7,500 7,500 Q2 '18 Q3 '18 Q4 '18 Q2'18 Q4'18 FY 2019 Hedged Volume (MMbtu/d) Average Floor ($/MMbtu) Average Ceiling ($/MMbtu) $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $ Note: Ceilings and floors reflect weighted average price and FY 2018 reflects Q2 18 through Q4 18 hedge positions. 22

23 Basis Hedges 25,000 20,000 15,000 10,000 5,000 Midland WTI Basis Swaps ($3.02) ($1.27) ($3.95) ($8.22) ($11.69) ($11.69) 8,000 8,000 8,000 8,000 12,000 4,000 Q2 '18 Q3 '18 Q4 '18 Q2'18 Q4'18 1H'19 2H'19 ($5.00) ($10.00) ($15.00) ($20.00) Hedged Volume (Bbl/d) Average Basis Swap 35,000 30,000 25,000 20,000 15,000 10,000 5,000 WAHA Gas Basis Swaps ($1.10) ($1.10) ($1.10) ($1.18) 25,500 15,000 15,000 10,036 Q2 '18 Q3 '18 Q4 '18 Q2'18 Q4'18 FY 2019 ($1.00) ($1.50) ($2.00) ($2.50) ($3.00) Hedged Volume (MMbtu/d) Average Basis Swap Note: Ceilings and floors reflect weighted average price and FY 2018 reflects Q2 18 through Q4 18 hedge positions. 23

24 Ownership Summary Ownership Summary as of 3/31/18 Basic Shares Basic Shares Employee Net Fully Fully Diluted Holder Outstanding % Ownership Warrants (1) Options (2) Diluted Diluted % Ownership Other Common Equity Holders 154,379, % 4,736, ,379, ,116, % Long Term Incentive Plan 6,077, % 0 7,587,837 6,077,937 13,665, % Total 160,457, % 4,736,842 7,587, ,457, ,782, % Note: Net Diluted shares based on 04/24/18 closing stock price of $5.20/share. (1) Warrants have a strike price of $14.04/share and a term of 4 years. (2) Employee options issued under the Long Term Incentive Plan with a weighted average strike price of $8.34/share; options vest ratably over 3 years. 24

25 Contact Information Quentin Hicks EVP Finance, Capital Markets and Investor Relations