Halcn Resources Investor Presentation August 2018 Forward Looking - - PowerPoint PPT Presentation

SLIDE 1

Halcón Resources Investor Presentation August 2018

SLIDE 2

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 1995. Forward‐looking statements are based on Halcón Resources’ current expectations beliefs, plans, objectives, assumptions and strategies. Forward‐looking statements

• ften, 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

• ur 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
• pinions 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.

Forward‐Looking Statements

SLIDE 3

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.

Cautionary Statements

SLIDE 4

Halcón Resources Overview

4 Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with drilling locations and EURs.

Delaware Basin Overview Total Company Acreage Position

Monument Draw Hackberry Draw

Total Company: Net Acreage: ~59,680 Operated Potential Gross Drilling Locations: 2,072 Current Production: 13,750 Net Boe/d (70% oil)

Monument Draw (Ward County)

• Net Acreage: ~21,987 with ~95% 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: ~10,834 with ~84% average W.I. (on operated

acreage)

• 407 gross potential operated drilling locations
• Wolfcamp EURs of ~2.2 MMBoe (~50% oil) assuming 10K’ laterals

Hackberry Draw (Pecos County)

• Net Acreage: ~26,859 with ~77% average W.I.
• 1,143 gross potential operated drilling locations
• Wolfcamp EURs of ~1.5 MMBoe (~75% oil) assuming 10K’ laterals

West Quito Draw

SLIDE 5

Focus for Investors

5

Issue HK Response Cash Flow and Liquidity ‐ $294 MM of current liquidity (6/30/18) ‐ Projected ample liquidity in all future periods until free cash flow positive status achieved (based on current internal forecasting) ‐ Potential infrastructure monetization further enhances liquidity (also value‐accretive) MidCush Basis Differential ‐ 2H ’18: 8,000 Bbl/d currently hedged at ‐$11.69 + 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 ‐$3.02 + Recently monetized swaps to realize $3.05/Bbl in value = Effective Premium of $0.03 on 12,000 Bbl/d Oil Takeaway ‐ Near‐term: 85%+ of oil on pipe in next few months (Modest discount to Midland) ‐ Longer term: Recently signed agreement for 25,000 Bbl/d of firm capacity on pipeline to Gulf Coast to be in service by 2H ‘19 (Premium to WTI) Well Costs ‐ Completion costs are moderating ‐ Significant opportunities to reduce costs as we gain scale (pads, local sand, etc.) Acquisitions ‐ No need or desire to significantly grow footprint with 2,000+ operated locations ‐ Focused on small “bolt‐on” opportunities or swaps to firm up units for long laterals

SLIDE 6

2nd Half 2018 Plan

Focused on Development, Delineation & Gaining Scale

6

2018 Plan Highlights

3 Rigs Running ‐ More rig time allocation to West Quito and Hackberry Combination of Development & Delineation Drilling

‐ Only drilling long laterals ‐ Transitioning to multi‐well pad development ‐ Drilling pilot wells and continuing to run shuttle logs to determine

• ptimal geo‐steering and frac design

Focus on Efficiencies

‐ Focus on reducing drilling days ‐ Utilize new technologies & techniques to optimize completions

Production Optimization

‐ Installation of jet pumps for artificial lift ‐ Improving power infrastructure to reduce power‐related downtime ‐ Focus on reducing downtime through proactive maintenance program

3 1 8 2 5 3 1 4

Q1 '18 Actual Q2 '18 Actual Q3 '18 Estimated Q4 '18 Estimated Monument Draw West Quito Draw Hackberry Draw

Gross Wells POL by Quarter Q4 ’17 to Q4 ’18 Production Growth

5,300 20,000

‐ 5,000 10,000 15,000 20,000 25,000

Production (Boe/d)

(1)

Q4 ’18 Estimated

Q4 ’17 Actual Pro Forma

(1) Reflects production for Delaware assets only (excludes Williston Basin production).

SLIDE 7

SR 6401H (POL 6/1/18)

‐ 24 Hour: 2,219 Boe/d ‐ 30‐Day: 1,756 Boe/d / 86% oil (rate continues to improve)

SR 9305H (POL 7/30/18)

‐ Well flowing back after frac

Telluride 6201H ‐ To be put online in early August SR 7702H (POL 7/16/18)

‐ 24 Hour: 1,350 Boe/d (rate continues to improve)

SR 7701H (POL 7/17/18)

‐ 24 Hour: 1,500 Boe/d (rate continues to improve)

Recent Well Results & 2H’18 POL Plan – Monument Draw

7

1 2 3 4 5

Recent Well 2‐Stream IP Results

1 2 3 4 5

SLIDE 8

• Up to 23 3rd BS/Upper/Lower Wolfcamp locations per 1,280

acre DSU(1)

Successful Spacing Result in Monument Draw

8

Micro‐Seismic Results – SR 7701H and SR 7702H

Micro‐Seismic indicates very little overlap in propped fracture systems supporting HK planned development spacing

SR 7701H (Lower WC) and SR 7702H (Upper WC) wells drilled on 330’ horizontal spacing and 250’ vertical spacing

Monument Draw Wolfcamp/3BS Development Spacing

660’ 250’

SR 7701H SR 7702H

WC/3BS Zone

(1) Number of locations varies depending on thickness of gross 3rd BS and WC interval across acreage.

SLIDE 9

2H’18 Plan – West Quito Draw

9

Halcon plans to put five Wolfcamp A wells online in West Quito Draw before year‐end (All ~10K Laterals)

SLIDE 10

Recent Well Results & 2H’18 POL Plan – Hackberry Draw

10

Johnny Hannah 1H (POL 8/1/18)

‐ Well flowing back after frac

Recent Well 2‐Stream IP Results

Bobby West 1H (POL 5/12/18)

‐ 24 Hour: 1,331 Boe/d ‐ 30‐Day: 1,069 Boe/d / 87% oil

1 1 2 2

SLIDE 11

Focus on Long Lateral Development

11

Average Completed Lateral Length (Ft.) Production Profile Comparison: 10,000’ vs. 5,000’

200,000 400,000 600,000 800,000 1,000,000 10 20 30 40 50 60 70

2‐phase Cumulative Production (boe)

Months on Production

Monument Draw Wolfcamp Lateral Productivity

5k lateral 10k lateral 9,567 8,853 8,053 7,887 7,786 7,310 5,996 5,741 ‐ 2,000 4,000 6,000 8,000 10,000 12,000 HK Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7

• Avg. CLL(1)

Peer Avg: 7,375 ft.

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 2018. Peers include Energen, Callon, Diamondback, Jagged Peak, Parsley, Centennial and RSP Permian. (2) Based on HK’s Monument Draw type curve using 7/10/18 strip pricing. 10K Lateral Doubles Production in First 5 Years of Well Life

• Halcón is focused on drilling long

laterals in all areas

• Near‐term impact:

‐ Longer cycle times ‐ Less capital efficient in 1st few months

• Long‐term impact:

‐ More capital efficient ‐ Lower PDP decline rates ‐ Better returns ‐ More valuable assets/company

• Economic benefits of 10K vs. 5K ft.

lateral:

‐ 1st 5 Years Production:

• 10K lateral: > 800K Boe
• 5K lateral: ~400K boe

‐ PV10(2):

• 10K lateral: $20 MM
• 5K lateral: $5 MM

‐ IRR(2):

• 10K lateral: 100%
• 5K lateral: 43%

SLIDE 12

$65.41 $3.05 $65.43 $55.01 $10.43 $3.02

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

$68.14 $7.79 $64.24 $53.31 $10.93 $11.69

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

Well Situated with Takeaway and Protected from Basis Blowout

12

Oil Takeaway Basis Hedges in Place HK is well‐positioned through 1H ‘19 with strong takeaway contracts in place and significant basis hedged

• Near‐Term Oil Takeaway:

‐ >85% of HK’s oil production is currently on pipe or will be on pipe by Q4 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 of firm space on pipeline to Gulf Coast (expected 2H 2019) ‐ Pricing likely a premium to NYMEX

Gas Takeaway

• Mid‐Cush Hedges Currently in Place:

‐ 2H ‘18: 8,000 bbl/d at ‐$11.69 ‐ 1H ’19: 12,000 bbl/d at $‐3.02

• April 2018 Mid‐Cush Hedge Monetization:

‐ Realized ~$31 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 $‐1.10 ‐ 25,500 Mmbtu/d for 2019 at $‐1.18

• 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)

Effective HK Midland Pricing – 2H ‘18 ($/Bbl)

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 7/24/18. 2. Calculated as ~$31 MM in hedge monetization proceeds related to hedges monetized in April 2018 divided by monetized mid‐cush hedge volumes for each time period.

Effective HK Midland Pricing – 1H ‘19 ($/Bbl)

(1) (2)

On 8,000 bopd of hedged production for 2H ’18 HK is effectively receiving a $10.93/bbl premium to current Midland pricing On 12,000 bopd of hedged production for 1H ’19 HK is effectively receiving a $10.43/bbl premium to current Midland pricing

(1) (1) (1) (1) (2) (2)

SLIDE 13

500 1,000 1,500 2,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Normalized Rate (Boe/d)

Normalized Time (Months)

Wolfcamp Type Curves ‐ 10,000’ Lateral

13 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 ~41% of NYMEX oil and current D&C costs.

Monument Draw (2‐Stream)(1) West Quito Draw (2‐Stream)(1)

D&C: ~$12.3 MM 2‐Stream EUR: 1.9 Mmboe (80% Oil, 20% Gas) 2‐Stream 30‐Day Peak IP: ~1,434 boe/d

500 1,000 1,500 2,000 2,500 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Normalized Rate (Boe/d)

Normalized Time (Months)

Hackberry Draw (2‐Stream)(1)

200 400 600 800 1,000 1,200 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

Normalized Rate (Boe/d)

Normalized Time (Months)

D&C: ~$10.6 MM 2‐Stream EUR : 2.2 Mmboe (50% Oil, 50% Gas) 2‐Stream 30‐Day Peak IP: 2,089 boe/d D&C: ~$10.75 MM 2‐Stream EUR: 1.5 Mmboe (75% Oil, 25% Gas) 2‐Stream 30‐Day Peak IP: 942 boe/d

SLIDE 14

Monument Draw WC Performance vs. Type Curve

14 Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with EURs.

Monument Wolfcamp Type Curve (1.9 Mmboe EUR)

SLIDE 15

First Year Cumulative Oil Production ‐ Wolfcamp

15

255,999 209,788 174,255 319,999 419,576 232,339

Monument Draw WC West Quito Draw WC Hackberry Draw WC

Oil (Bbls) Combined (Boe)

Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with EURs. Based on 2‐stream production and no downtime.

West Quito Draw’s Projected First Year Cumulative Oil is Prolific. Natural Gas and NGLs will Add to Profitability of Drilling Here

SLIDE 16

Multiple Targets Across All Acreage

16

Monument Draw Type Log West Quito Draw Type Log Hackberry Draw Type Log

Top Seal

3rd BS Shale 1st & 2nd BS Shale 3rd BS Sand Deep Wolfcamp Sands Base Case Target (Already De‐Risked) Upside Target (To Be De‐Risked) Deep Woodford

3,600’ 3,520’ 2,630’

Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with drilling locations and EURs and the meaning of “de‐risked”.

SLIDE 17

Decades of Drilling Inventory

17

Gross Remaining Operated Locations (1) Locations by Area

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.

De‐risked base case drilling inventory Additional targets

Inventory Length (Years)(2)

Gross Locations Net Locations

Operated Rigs Running

Monument Draw Hackberry Draw West Quito Draw

527 405 1,140 494 301 751 58 43 35 29 25 ‐ 20 40 60 80 3 4 5 6 7 305 435 117 199 56 960 1,112 2,072

3rd 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

SLIDE 18

Halcón Field Services

18

Area Surface Acreage Water Gathering Pipelines Produced Water Capacity Fresh Water Capacity Water Storage Capacity Gas Gathering, Compression & Treating Crude Gathering and Storage Monument Draw

• 1,768 acres
• 20 miles of pipe

(12”)

• 23,000 bwpd of injection (4

wells)

• 30,000 bwpd of recycling (1

facility)

• 10 wells with 60,000

bwpd of capacity

• Additional capacity

available

• 860,000 bbl produced /

recycled water storage

• 1,100,000 bbls of fresh

water storage

• 14 MMCFPD of treating capacity
• 2,720 of compression capacity
• Building gas gathering pipelines
• 27 miles of pipe (>8”)
• 10,000 bbl crude storage

capacity West Quito Draw

• Currently

pursuing surface acquisitions

• Constructing 4

miles (12”)

• Constructing 30,000 bwpd

recycling facility

• Planning SWD wells
• Planning fresh water

wells

• Constructing 860,000

bbl produced / recycled water storage

• Handled by Crestwood
• Constructing 4 miles

(12”)

• Constructing 10,000 bbl

crude storage facility Hackberry Draw

• 3,243 acres
• 32 miles of pipe (>

8”)

• 45,000 bwpd of injection (3

wells)

• 140,000 bw/d of recycling

(4 facilities)

• 4 wells with 40,000 bwpd
• f capacity
• Additional capacity

available

• 3,500,000 bbl produced

/ recycled water storage

• 2,400,000 bbls of fresh

water storage

• 41 miles of steel/poly pipe (>6”)
• 24 MMCFPD of treating /

compression capacity

• Gas sweetening, dehy and JT unit
• Handled by ETC

Monument Draw Infrastructure Hackberry Draw Infrastructure West Quito Draw Infrastructure

RECYCLING PLANT

SLIDE 19

Halcón Field Services

Water Handling and Recycling

19

Water Handling Capacity vs. Forecast (1) Water Recycling vs. Frac Water Needs (1)(2)

(1) Based on most recent production forecasts and midstream facility build‐outs for Monument Draw, Hackberry Draw, and West Quito Draw. (2) Chart assumes 75‐100% 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.

• Continuing to develop produced water

recycling and injection capabilities throughout each asset (see previous slide)

• Maintaining capacity above forecasted

volumes critical for potential downtime associated with maintenance or workovers

• n midstream facilities
• Critical for LOE/GTO cost control
• Since start of operations in Delaware, ~70%
• f water used for completions (~6.5 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
• ur completion schedule
• Critical for capex cost control (saves ~30‐

40% vs. sourcing water from 3rd parties) 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 Recycled Water Available for Use Recycled Water Demand for Frac's

SLIDE 20

Oil & Gas Marketing & Takeaway

20

Oil Marketing & Takeaway

Monument Draw West Quito Draw Hackberry Draw

Gas Marketing & Takeaway

‐ Current:

• All oil sold via truck to single buyer
• Pricing: Midland less ~$4.00/bbl

‐ Projected Oct. ‘18:

• All oil taken to Wink via pipeline constructed

by 3rd party midstream company

• 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

HK Has Contracts in Place to Handle All Projected Oil and Gas Production with No MVCs

‐ Current:

• All oil sold via truck to single buyer
• Pricing: Midland less ~$3.25/bbl

‐ Projected Dec. ‘18:

• All oil taken to Wink via pipeline constructed

by 3rd party midstream operator

• 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

‐ Current:

• ~70% sold via pipeline and remainder

trucked; All sold to Sunoco under a deal 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

‐ Primary Plan:

• Contract in place through 2032 with 3rd

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
• ur gas
• Pricing: WAHA flat

‐ Back‐up Plan:

• Multiple low and high pressure sales points

with ETC ‐ 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 3rd party midstream operator will

have high pressure sales connection by late 2018 ‐ Primary Plan:

• Contract in place with Crestwood through

2036 to gather and compress gas from wellhead

• High pressure wet gas will be delivered to 3rd

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

SLIDE 21

Capitalization & Debt Maturities

21

Pro Forma Capitalization  Simple capital structure  No near‐term debt maturities  Strong liquidity of $294 MM Maturity Schedule

$200 $625 $‐ $100 $200 $300 $400 $500 $600 $700 2018 2019 2020 2021 2022 2023 2024 2025 2026

Senior Revolver Senior Notes

Face Value Actual Capitalization ($MM) 6/30/2018 Cash & Cash Equivalents 96 $ Senior Secured Revolving Credit Facility ‐ 6.75% Senior Unsecured Notes due 2025 625 Total Debt 625 $ Total Net Debt / (Cash) 529 $ Stockholders' Equity 1,123 Total Capitalization 1,748 $ Borrowing Base 200 $ Less: Borrowings ‐ Less: Letters of Credit (2) Plus: Cash 96 Total Liquidity 294 $

SLIDE 22

2018 Guidance

22

(1) Excludes capitalized G&A.

Q3 2018 Q4 2018 Full Year 2018

Production (Boe/d)

Total 14,500 – 15,500 19,000 – 21,000 14,000 – 16,000 % Oil 66% – 70% % Gas 15% – 17% % NGL 15% – 17%

Capex(1) ($MM)

D&C Capex $390 ‐ $440 Infrastructure, Seismic and Other Capex $90 – $110

Operating Costs and Expenses ($/Boe)

Lease Operating & Workover $4.50 – $5.50 Gathering, Transportation & Other $4.50 – $5.50 Production Taxes 6% – 7% Cash G&A $40 ‐ $44 Million

SLIDE 23

Investment Highlights

23

Significant Inventory Excellent Growth Profile Strong Balance Sheet Compelling Return Profile Attractive Valuation

• ~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
• Q4 ’17 to Q4’18 expected production growth in excess of 300%
• Significant long‐term growth potential
• Strong current liquidity of ~$294 MM
• No near‐term debt maturities
• Planned HFS sale will bolster liquidity
• Well‐level IRRs of 50% to 100% at current strip
• Strong corporate level returns
• 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

SLIDE 24

Appendix

SLIDE 25

Commodity Hedges

25

Crude Oil (Bbl/d, $/Bbl) Q3 '18 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 (Bbl/d) 10,000 13,000 11,500 15,000 15,000 16,000 16,000 15,504 1,500 1,500 1,500 1,500 1,500 Ceiling (1) $55.98 $56.87 $56.48 $58.49 $59.23 $59.84 $59.84 $59.37 $70.00 $70.00 $70.00 $70.00 $70.00 Floor (1) $48.96 $50.08 $49.59 $52.69 $53.24 $53.35 $53.35 $53.17 $50.00 $50.00 $50.00 $50.00 $50.00 Weighted Average Price (2) $52.47 $53.47 $53.03 $55.59 $56.24 $56.60 $56.60 $56.27 $60.00 $60.00 $60.00 $60.00 $60.00 Mid‐Cush Differential Swap (Bbl/d) 8,000 8,000 8,000 12,000 12,000 4,000 4,000 7,967 ‐ ‐ ‐ ‐ ‐ Basis Swap ($11.69) ($11.69) ($11.69) ($3.02) ($3.02) ($3.95) ($3.95) ($3.26) $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ Houston‐Cush Differential Swap (Bbl/d) ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 6,000 6,000 6,000 6,000 6,000 Basis Swap $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ $2.56 $2.56 $2.56 $2.56 $2.56 Natural Gas (MMBtu/d, $/MMBtu) Q3 '18 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 7,500 20,000 20,000 20,000 20,000 20,000 ‐ ‐ ‐ ‐ ‐ Ceiling (1) $3.30 $3.30 $3.30 $3.01 $3.01 $3.01 $3.01 $3.01 $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ Floor (1) $3.01 $3.01 $3.01 $2.59 $2.59 $2.59 $2.59 $2.59 $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ Weighted Average Price (2) $3.16 $3.16 $3.16 $2.80 $2.80 $2.80 $2.80 $2.80 $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ WAHA Gas Differential Swap (MMBtu/d) 15,000 15,000 15,000 25,500 25,500 25,500 25,500 25,500 ‐ ‐ ‐ ‐ ‐ Basis Swap ($1.10) ($1.10) ($1.10) ($1.18) ($1.18) ($1.18) ($1.18) ($1.18) $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ Natural Gas Liquids (Bbl/d, $/Bbl) Q3 '18 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) ‐ ‐ ‐ 2,500 2,500 2,500 2,500 2,500 ‐ ‐ ‐ ‐ ‐ Swap (1) $ ‐ $ ‐ $ ‐ $29.09 $29.09 $29.09 $29.09 $29.09 $ ‐ $ ‐ $ ‐ $ ‐ $ ‐ (1) Weighted average price. (2) Based on average of swap price and midpoint of ceiling / floors of collars. (3) FY 2018 data based on Q3' 18 through Q4 '18.

SLIDE 26

Ownership Summary

26

Ownership Summary as of 7/20/18 Basic Shares Basic Shares Employee Net Fully Fully Diluted Holder Outstanding % Ownership Warrants (1) Options (2) Diluted Diluted % Ownership Other Common Equity Holders 154,379,981 96.1% 4,736,842 154,379,981 159,116,823 92.0% Long‐Term Incentive Plan 6,239,872 3.9% 7,587,837 6,239,872 13,827,709 8.0% Total 160,619,853 100.0% 4,736,842 7,587,837 160,619,853 172,944,532 100.0% Note: Net Diluted shares based on 07/25/18 closing stock price of $3.78/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.