Halcón Resources Investor Presentation November 2018

Transcription

1 Halcón Resources Investor Presentation November 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 Delaware Basin Overview Total Company Acreage Position Monument Draw (Ward County) Net Acreage: ~22,110 with ~94% average W.I. 588 gross potential operated drilling locations Wolfcamp EURs of ~1.9 MMBoe (~80% oil) assuming 10K laterals West Quito Draw (Ward County) Net Acreage: ~11,008 with ~82% average W.I. (on operated acreage) 409 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: ~23,816 with ~78% average W.I. 901 gross potential operated drilling locations Wolfcamp EURs of ~1.5 MMBoe (~75% oil) assuming 10K laterals Total Company: Net Acreage: ~56,934 Operated Potential Gross Drilling Locations: 1,898 Current Production: ~17,500 Net Boe/d (~70% oil) Hackberry Draw Note: See Cautionary Statements on page 3 for a discussion on risks associated with drilling locations and EURs. 4

5 Recent Achievements Achievement Commentary Raised $200 MM through water infrastructure sale ($325 MM total valuation) Successful Infrastructure Sale Results in pro forma liquidity of $418 MM (1) as of 9/30/18 Firm capacity for all anticipated future water handling needs in place HK retains 100% of oil and gas infrastructure assets = Significant Future Value Five new wells in MD with an avg. 30 day peak IP rate of 1,753 Boe/d (80% oil) (2) Continued Strong Well Results Contracted Firm Oil Takeaway Good Q Execution Two wells in Monument Draw set new HK 30 day IP records Trinity 6205H: 2,182 Boe/d (83% oil) Telluride 6201H: 1,991 Boe/d (80% oil) Signed firm long haul takeaway contract to Gulf Coast 25,000 Bbl/d of firm capacity (gross) Expected to be in service 2H 19 (EPIC pipeline) Strong oil production of 10,652 bo/d Adjusted LOE and adjusted GTO costs per BOE declined significantly vs. Q2 18 Q3 18 capex was below Q2 18 levels and in line with expectations (1) Pro forma for upfront proceeds of $200 MM from the announced water infrastructure sale and the recently redetermined borrowing base of $275 MM. (2) Excludes three wells which were put online in the third quarter but have not yet reached their 30 day peak IP rates. See slide 9 for detail. 5

6 Halcón s Strategic Rationale for the Midstream Transaction Generate Proceeds to Enhance Leverage and Liquidity Position Focus on Accelerating Upstream Development Demonstrate the Embedded Value of Midstream Operations Retain Economic Interest in the Growing Oil & Gas Midstream Operations Provide Firm Capacity for Future Water Handling Needs with Reputable Party Transaction Enables HK to Achieve Several Strategic and Financial Objectives 6

7 Near Term Drilling Plan Focused on Efficiencies & Gaining Scale 3 Operated Rigs Running 1 rig in each area Near Term Plan Highlights Hackberry Draw focused on northern acreage where we see stronger results Focus on Improving Efficiencies Only drilling long laterals (>9,500 ft.) Only multi well pad drilling and completions going forward Increased use of local brown sand (i.e. 100 mesh) Increased clusters on some wells Production Optimization Replace ESPs with more reliable jet pumps Focus on reducing downtime through proactive maintenance program Benefits of Jet Pump Installation Flowing Jet Pump Days, 1 st Intermediate Spud to RR Monument Draw Drilling Efficiencies Q17 4Q17 1Q18 2Q18 3Q18 RECORD 4.7 Days, Int. spud to TD Previous Operator Hackberry Draw Drilling Efficiencies Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Record Well Faye Faye West 1H

8 Attractive Break Even Well Economics Attractive Break Even Economics (1) $ / Bbl (2) Source: Baker Hughes, Wood Mackenzie, Advisor analysis 1. Breakevens represent IRRs of 10% and assume gas prices of: $3.03/Mcf in 2018, $2.88/Mcf in 2019, $3.04/Mcf in 2020, $3.28/Mcf in 2021 and $3.34/Mcf in 2022+, inflated at 2% per annum thereafter 2. Represents average break even oil pricing across HK s Delaware Basin Wolfcamp type curves, pro forma for HK s divestment of midstream water business. 8

9 Monument Draw Recent Well Results 2 Stream IP Results SR 6401H (POL 6/1/18) 24 Hour: 2,219 Boe/d 30 Day: 1,869 Boe/d / 86% oil 60 Day 1,785 Boe/d / 86% oil SR 7701H (POL 7/17/18) 24 Hour: 1,767 Boe/d 30 Day: 1,381 Boe/d / 83% oil 60 Day: 1,178 Boe/d / 83% oil SR 7702H (POL 7/16/18) 24 Hour: 2,097 Boe/d 30 Day: 1,755 Boe/d / 77% oil 60 Day: 1,602 Boe/d / 77% oil 1 4 SR 9305H (POL 7/30/18) 24 Hour: 1,690 Boe/d 30 Day: 1,457 Boe/d / 77% oil 60 Day: 1,327 Boe/d / 76% oil Telluride 6201H (POL 8/6/18) 24 Hour: 2,336 Boe/d 30 Day: 1,991 Boe/d / 80% oil 60 Day: 1,791 Boe/d / 80% oil 5 6 Trinity 6205AH (POL 8/15/18) 24 Hour: 2,614 Boe/d 30 Day: 2,182 Boe/d / 83% oil (record 30 day IP for HK) 60 Day: 1,889 Boe/d / 82% oil (record 60 day IP for HK) 7 SR 8801H (POL 9/6/18) Current 30 Day Rate of 1,226 boe/d & increasing (78% oil) Restricted flowback choke levels vs. previous wells 8 SR 8705H (POL 9/16/18) Current 30 Day Rate of 1,330 boe/d & increasing (79% oil) Restricted flowback choke levels vs. previous wells 9 SR 7506H (POL 9/22/18) Cut oil Oct 5; Shut in in Mid Oct. given gas treating constraints 9

10 Monument Draw Excellent First Month Oil Productivity HK s Monument Draw Peak Month Oil Production vs. Peers (Bbls) 60,000 HK 30 Day Avg. Oil Rate: 41,782 Bbl (2) 54,258 50,000 43,937 45,678 48,130 48,091 40,000 33,764 34,345 35,727 40,387 33,505 33,367 30,000 20,000 10,000 Sealy Ranch 7902H Sealy Ranch 7701H Sealy Ranch 9301H Sealy Ranch 7702H Sealy Ranch 5902H Sealy Ranch 7903H Sealy Ranch 6401H Sealy Ranch 9305H Telluride 6201H Trinity 6205H Peer Average Long Lateral (1) HK s Peak Monthly Oil Production is 25% Higher than the Peer Average (1) Peer data obtained from DrillingInfo. Peer well results include all wells drilled since 1/1/17 in Ward and Reeves Counties with lateral lengths greater than 9,000 ft. (2) HK well data based on internal production data and includes all wells for which HK has reached 30 day peak IP rates. 10

11 Monument Draw Spacing Test Support HK has successfully demonstrated its ability to decrease spacing without experiencing parent child interference Spacing Test Pad Overview 7701H and 7702H Microseismic Results Historical Spacing Tests Program & Results Sealy Ranch 7901H, 7902H and 7903H Tested 660 Spacing Lower WC Target Sealy Ranch 7701H & 7702H Successfully tested 330 horizontal spacing & 250 vertical spacing Microseismic (pictured above) indicates little to no overlap in propped fracture systems Results support development program of 330 stagger/stacked horizontal spacing 11

12 Hackberry Draw Spacing Test Support Spacing Test Pad Overview Belle Alexandra Microseismic Results Historical & Future Spacing Test Programs Jose Katie East 1H & West 1H (currently drilling) Tested 660 spacing WC B target Belle Alexandra 1H / Belle Alexandra A 2H Successfully tested 330 horizontal & vertical spacing 1H drilled in WC A Lower 2H drilled in 3 rd BS Microseismic (pictured above) shows frac containment in target Results confirms 660 spacing in WC A Lower Supports potential stagger/stacked pattern drilling Confirms 1320 well spacing in 3 rd BS Supports potential to tighten spacing Bailey 3H & 4H (currently flowing back after frac) Testing 660 spacing WC A Lower target 12

13 West Quito Draw Shuttle Log HK is Planning to Rapidly De Risk West Quito Draw and Early Data is Very Positive 13

14 Monument Draw Inventory Summary Stacked Reservoirs Provide Significant Development Inventory and Upside Opportunity Development Inventory Summary (Gross) Monument Draw Type Log Avalon Lateral Development Targets Upside Development Targets Wells / DSU (1) 4 Remaining Inventory (2) 74 Bone Spring 1st 2nd 3rd Wolfcamp Total: Inventory Derivation Methodology Development plan locations are based on the area s geologic prospectivity and local offset development activity ~22,700 gross acres for development Contiguous acreage provides for full development of 10,000 foot lateral lengths at 660 foot spacing 1. Chart represents a fully developed 1,280 acre unit 2. Well count represents total inventory remaining for each bench as of August Lateral Development Targets Upside Development Targets 14

15 West Quito Draw Inventory Summary Tremendous Upside Potential in Undeveloped Bone Spring and Avalon Formations Development Inventory Summary (Gross) West Quito Draw Type Log Avalon Lateral Development Targets Upside Development Targets Wells / DSU (1) 4 Remaining Inventory (2) 50 1st 4 50 Bone Spring 3rd 2nd Wolfcamp B AL AU Development plan locations are based on the area s geologic prospectivity and local offset development activity ~17,600 gross acres for development Inventory Derivation Methodology Total: Contiguous acreage provides for full development of 10,000 foot lateral lengths at 660 foot spacing 1. Chart represents a fully developed 1,280 acre unit 2. Well count represents total inventory remaining for each bench as of August 2018 Lateral Development Targets Upside Development Targets 15

16 Hackberry Draw Inventory Summary Thick Bone Spring and Wolfcamp Reservoirs Allow for Stacked Lateral Development Development Inventory Summary (Gross) Lateral Development Targets Upside Development Targets Wells / DSU (1) Remaining Inventory (2) Hackberry Draw Type Log Avalon st 4 94 Bone Spring 3rd 2nd Wolfcamp B AL AU Development plan locations are based on the area s geologic prospectivity and local offset development activity ~31,250 gross acres for development Inventory Derivation Methodology Total: Contiguous acreage provides for full development of 10,000 foot lateral lengths at 660 foot spacing 1. Chart represents a fully developed 1,280 acre unit 2. Well count represents total inventory remaining for each bench as of October 2018 Lateral Development Targets Upside Development Targets 16

17 Well Situated with Takeaway and Protected from Basis Blowout Near Term Oil Takeaway: Oil Takeaway >85% of HK s oil production is currently on pipe or will be on pipe by year end 2018 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: Agreement in place for 25,000 bbl/d (gross) of firm space on pipeline to Gulf Coast (expected 2H 2019) Pricing likely apremium to NYMEX Primary Plan Gas Takeaway L T firm commitment contracts in all areas for third party midstream operators to take high pressure wet gas to their processing plants L T firm commitments in place to take NGLs to Gulf Coast for fractionation 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) MidCush Basis Swaps In Place (Bbls/d) Waha Basis Hedges in Place (Mmbtu/d) 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 14,000 ($3.58) / Bbl 5,000 ($4.54) / Bbl 1H H ,000 25,000 20,000 15,000 10,000 5,000 25,500 ($1.18) / Mmbtu 2019 HK is well positioned 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. 17

18 Halcón Field Services Overview of Retained Oil & Gas Infrastructure Assets Area Surface Acreage Gas Gathering, Compression & Treating Crude Gathering and Storage Monument Draw 1,768 acres Building 20 miles of high spec gas gathering pipelines 25 MMCFPD of treating capacity 2,720 of compression HP Liquid redox Valkyrie system unit under construction 27 miles of pipe (>8 ) 10,000 bbl crude storage capacity West Quito Draw 80 acres Handled by Crestwood Constructing 4 miles (12 ) Constructing 10,000 bbl crude storage facility Hackberry Draw 3,243 acres 41 miles of steel/poly pipe (>6 ) 4,260 of compression HP 24 MMCFPD of treating / compression capacity Gas sweetening, dehy and JT unit Handled by ETC through August 2019 Monument Draw Infrastructure Hackberry Draw Infrastructure West Quito Draw Infrastructure 18

19 Capitalization & Debt Maturities Pro Forma Capitalization Maturity Schedule Water Face Value Actual Infrastructure Pro Forma Capitalization ($MM) 9/30/2018 Monetization (2) 9/30/2018 $700 Senior Revolver Senior Notes $625 Cash & Cash Equivalents $ $ 145 $ 145 $600 Senior Secured Revolving Credit Facility % Senior Unsecured Notes due Total Debt $ 680 $ 625 Total Net Debt / (Cash) $ 680 $ 480 Stockholders' Equity 1,046 1,046 Total Capitalization $ 1,726 $ 1,671 (1) Borrowing Base $ 200 $ 75 $ 275 Less: Borrowings (55) 55 Less: Letters of Credit (2) (2) Plus: Cash Total Liquidity $ 143 $ 275 $ 418 (1) Reflects revised borrowing base increase effective upon the water infrastructure sale closing. (2) Transaction is expected to close in December $500 $400 $300 $200 $100 $ $ Simple capital structure No near term debt maturities Strong pro forma liquidity of $418 MM 19

20 Q Guidance Q Production (Boe/d) Total 18,000 20,000 % Oil 63% 67% Capex (1) ($MM) D&C Capex $75 $95 Infrastructure Capex (excluding water infrastructure) $20 $30 (1) Excludes capitalized G&A. 20

21 Commodity Hedges Crude Oil (Bbl/d, $/Bbl) Q4 '18 FY 2018 Q1 '19 Q2 '19 Q3 '19 Q4 '19 FY 2019 Q1 '20 Q2 '20 Q3 '20 Q4 '20 FY 2020 (4,5) Costless Collars (Bbl/d) 13,000 13,000 15,000 15,000 16,000 16,000 15,504 4,000 4,000 4,000 4,000 4,000 Ceiling (1) $59.68 $59.68 $58.49 $59.23 $59.84 $59.84 $59.37 $67.00 $67.00 $67.00 $67.00 $67.00 Floor (1) $49.84 $49.84 $52.69 $53.24 $53.35 $53.35 $53.17 $50.13 $50.13 $50.13 $50.13 $50.13 Weighted Average Price (2) $54.76 $54.76 $55.59 $56.24 $56.60 $56.60 $56.27 $58.56 $58.56 $58.56 $58.56 $58.56 Mid Cush Differential Swap (Bbl/d) 11,000 11,000 14,000 14,000 6,000 4,000 9,463 Basis Swap ($10.64) ($10.64) ($3.58) ($3.58) ($4.94) ($3.95) ($3.83) $ $ $ $ $ Houston Cush Differential Swap (Bbl/d) 5,000 1,260 9,000 9,000 9,000 9,000 9,000 Basis Swap $ $ $ $ $ $3.72 $3.72 $2.95 $2.95 $2.95 $2.95 $2.95 Natural Gas (MMBtu/d, $/MMBtu) Q4 '18 FY 2018 Q1 '19 Q2 '19 Q3 '19 Q4 '19 FY 2019 Q1 '20 Q2 '20 Q3 '20 Q4 '20 FY 2020 Costless Collars (MMbtu/d) 7,500 7,500 24,000 24,000 24,000 24,000 24,000 Ceiling (1) $3.30 $3.30 $3.01 $3.01 $3.01 $3.01 $3.01 $ $ $ $ $ Floor (1) $3.01 $3.01 $2.60 $2.60 $2.60 $2.60 $2.60 $ $ $ $ $ Weighted Average Price (2) $3.16 $3.16 $2.81 $2.81 $2.81 $2.81 $2.81 $ $ $ $ $ WAHA Gas Differential Swap (MMBtu/d) 15,000 15,000 25,500 25,500 25,500 25,500 25,500 Basis Swap ($1.10) ($1.10) ($1.18) ($1.18) ($1.18) ($1.18) ($1.18) $ $ $ $ $ Natural Gas Liquids (Bbl/d, $/Bbl) Q4 '18 FY 2018 Q1 '19 Q2 '19 Q3 '19 Q4 '19 FY 2019 Q1 '20 Q2 '20 Q3 '20 Q4 '20 FY 2020 NGL Swaps (Bbl/d) 1,000 1,000 4,000 4,000 4,000 5,000 4,252 2,000 2,000 2,000 2,000 2,000 Swap (1) $32.50 $32.50 $29.33 $29.33 $29.33 $29.96 $29.51 $31.00 $31.00 $31.00 $31.00 $31.00 (1) Weighted average price. (2) Based on average of swap price and midpoint of ceiling / floors of collars. (3) FY 2018 data based on Q4 '18. (4) Excludes 1,500 bbl/d of $70.00 calls. (5) Floor price includes 2,500 bbls/d of $55/bbl deferred premium puts with a $4.80 premium (i.e. $50.20 effective floor) 21

22 Investment Highlights Significant Inventory ~57,000 net acres in the oily window of the Delaware Basin (~70% oil) Over 1,900 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 250% Significant long term growth potential Strong Balance Sheet Strong current liquidity of ~$418 MM (pro forma for water infrastructure sale and revised borrowing base) 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 22

23 Appendix

24 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: Modest discount to Midland Projected Dec. 18: All oil taken to Wink via pipeline constructed Salt Creek Midstream Pricing: Modest discount to Midland 2H 2019: Recently signed agreement for firm space to Gulf Coast (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 ~$1.50/bbl Projected Dec. 18: All oil taken to Wink via pipeline constructed by Salt Creek Midstream Pricing: Modest discount to Midland 2H 2019: Recently signed agreement for firm space to Gulf Coast (5K bbl/d) with flexibility to scale up or down over time 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 ~$1.25/bbl By Q1 19, expect 90% to be sold via pipeline Aug. 19: Current gathering deal expires in Aug. 19 Negotiating w/ several midstream companies to provide oil takeaway options including long haul optionality Realized pricing likely at premium to Midland Gas Marketing & Takeaway Primary Plan: Contract in place through 2032 with Salt Creek Midstream to take wet gas to their processing plant via high pressure pipeline Multiple sales outlets from tailgate of plant (El Paso, Comanche Trail and Roadrunner) Firm commitment in place to take and sell our gas and NGLs Pricing: WAHA flat Back up Plan: Multiple low and high pressure sales points with ETC Primary Plan: Contract in place with Crestwood through 2036 to gather and compress gas from wellhead High pressure wet gas will be delivered to Salt Creek Midstream and taken to their processing plant under same terms as Monument Draw (i.e. firm commitment) Pricing: WAHA flat Back up Plan: Crestwood has several other outlets to move gas to various plants in the Delaware Basin Primary Plan: Contract in place through 2027 with ETC to take wet gas to their Arrowhead processing plant via high pressure line All pipes at WAHA available under this deal HK has firm capacity for gas and NGLs that is expandable Pricing: WAHA less ~$.03/Mmbtu Back up Plan: Multiple low pressure sales points with ETC Salt Creek Midstream will have high pressure sales connection by Feb. 19 HK Has Contracts in Place to Handle All Projected Oil and Gas Production with No MVCs 24

25 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. 25

26 Decades of Drilling Inventory Gross Remaining Operated Locations (1) De risked base case drilling inventory Additional targets , , rd BS/WC (Monument) 2 WC Zones (Hackberry) 3rd BS (Hackberry) 2 WC Zones (West Quito) 3BS (West Quito) Total Base Case Locations Additional Locations (Monument, Hackberry & West Quito) Total Potential Locations Gross Locations 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 Inventory Length (Years) (2) Operated Rigs Running 26

27 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: ~$12.6 MM 2 Stream EUR: 1.9 Mmboe (80% Oil, 20% Gas) 2 Stream 30 Day Peak IP: ~1,434 boe/d Normalized Rate (Boe/d) 2,500 2,000 1,500 1, Normalized Time (Months) 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 Normalized Rate (Boe/d) 1,200 1, Normalized Time (Months) Hackberry Draw (2 Stream) (1) D&C: ~$10.9 MM 2 Stream EUR: 1.5 Mmboe (75% Oil, 25% Gas) 2 Stream 30 Day Peak IP: 942 boe/d 27 Note: See Cautionary Statements on page 3 for a discussion on risks associated with EURs. (1) Assumes a $3.00/MMBtu Henry Hub gas price and NGL pricing of ~49% of NYMEX oil and current D&C costs. Includes impact of higher water handling costs associated with water infrastructure divestiture.

28 Monument Draw WC Performance vs. Type Curve Monument Wolfcamp Type Curve (1.9 Mmboe EUR) Note: See Cautionary Statements on page 3 for a discussion on risks associated with EURs. 28

29 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. 29

30 Monument Draw Gas Treating Plan Q3 18 Q4 18 Q1 19 Q2 19 2H 19 + Beyond Highest Cost Lower Cost Lower Cost Lowest Cost L T Solution Treating Plan: Treat gas at the wellhead via bubble towers with chemicals for sales to sweet gas line or flaring Infrastructure Development: Started construction of high spec gas gathering system and compression; Entered into a contract to build a centralized liquid redox treating system at central production facility Treating Plan: Reduced wellhead treating given new 3 rd party sour gas line capacity Infrastructure Development: Continued construction of high spec gas gathering system and compression; Start building centralized liquid redox treating system at central production facility (operational by end of Q1 19) Treating Plan: Eliminate wellhead chemical treating by utilizing centralized liquid redox treating system for sales to sweet gas line Infrastructure Development: Continue development AGI/Amine facility Treating Plan: Utilize AGI/Amine facility for all gas treating and sales to sweet gas line ~$13 MM Q4 18: $10 12 MM / $ per Mcf (1) Q1 19: $ MM / $3.75 ~$ per Mcf (1) ~$ per Mcf (1) 5.00 per Mcf (1) (1) Based on gross wellhead gas volumes. Long Term Lower Cost Solutions on Track for Operation in Q2 Q

31 Ownership Summary Ownership Summary as of 11/1/18 Basic Shares Basic Shares Employee Net Fully Fully Diluted Holder Outstanding % Ownership Warrants (1) Options (2) Diluted Diluted % Ownership Other Common Equity Holders 153,983, % 4,736, ,983, ,719, % Long Term Incentive Plan 6,616, % 0 7,476,471 6,616,756 14,093, % Total 160,599, % 4,736,842 7,476, ,599, ,813, % Note: Net Diluted shares based on 10/31/18 closing stock price of $3.32/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 $8.84/share; options vest ratably over 3 years. 31