Halcón Resources Investor Presentation

May 2019

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 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.

Forward-Looking 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.

Cautionary Statements

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: ~56,704

Operated Potential Gross Drilling Locations: ~1,800

Monument Draw (Ward County)

• Net Acreage: ~22,216 with ~95% average W.I.

• ~600 gross potential operated drilling locations

West Quito Draw (Ward County)

• Net Acreage: ~10,856 with ~83% average W.I. (on operated acreage)

• ~425 gross potential operated drilling locations

Hackberry Draw (Pecos County)

• Net Acreage: ~23,633 with ~87% average W.I.

• ~775 gross potential operated drilling locations

West Quito Draw

2019 Initiatives

5

Initiative Commentary

Grow Production in Capital Efficient Manner

- 2 rig program focused on highest returning assets (1.7 rigs in MD and 0.3 in WQD)

• All remaining drilling focused on Monument Draw

- Only multi-well pad development

- Continue improving cycle times (i.e. reduced drilling days and improved frac efficiencies)

Reduce H2S Treating Costs and Ensure Flow Assurance of Gas in Monument Draw

- Valkyrie treating plant became operational in early April 2019

• Treating costs are expected to decline to be $2.50 - $3.25/Mcf beginning 2Q ’19 and beyond

- Pursuing back-up for sour gas sales agreement(s) with third party midstream companies to provide assurance of ability to treat/handle sour gas as MD production grows

- Pursuing acid gas injection well (AGI)

- Targeting permit approval in Q3 ’19 and mid 2020 in-service date

- Reduces treating costs to ~$0.50 - $1.00/Mcf

Investigate M&A and Ensure Adequate Liquidity and Balance Sheet Health

- Reviewing M&A opportunities

- Exploring financing options

• Goal is to ensure adequate liquidity and provide financial flexibility

Cost Reductions

- Cutting corporate G&A by > $10 MM annually from 2018 levels

- Continue to reduce D&C costs through drilling and completion efficiency improvements

• Most recent wells drilled in MD have been record wells with significantly lower costs

333

427 413 428 349

446 492 481

665 597

538

SR 6401H (10K')SR 9305H (10K') Trinity 6205AH(10K')

Telluride 6201H(10K')

SR 8801H (10K')SR 8705H (10K') SR 7805AH(5K')

SR 7905AH(5K')

SR 9302H(7.5k')

SR 9303H(7.5K')

SR 7501H (10K')

Monument Draw Drilling Efficiency Gains (Total Feet Drilled per Day)

Recent Drilling and Completion Efficiency Gains

Ward County Completion Efficiency Gains ($ Completion Cost / Stage)

RECORD WELLS (1st Slim Hole Design)

$93,905

$72,089 $67,308

Q3 '18 Beginning Q4 '18 End of Q4 '18

63%

59% 57% 57%

55% 54% 52% 52% 51% 51%

49% 49% 48%

42%

32%

HalconResources

Operator A Operator B Operator C All OtherOperators

Operator D Operator E Operator F Operator G Operator H Operator I Operator J Operator K Operator L Operator M

% o

f Ti

me

Pu

mp

ing

% of Time Pumping Zipper Wells in Permian (2018)

Halcón is Liberty’s Most Efficient Permian Operator

Source: Liberty Oilfield Services.

Number of

Completions23 61 16 4 19 54 27 24 8 19 2 10 102 2 2

Efficient Frac Operations Drive Cost Savings for HK

Monument Draw Development Plan

Drilling Rig & Completion Crew Assumptions Well Layout & 2019 Drilling Plan

• 2019 forecast assumes 1.7 rigs running, with 1 frac crew spotted as needed to maintain minimal DUC inventory

– 10 wells to be spud from 5 different pads

– 4 wells put online (POL) to date

– 8 wells remaining to POL

Monument Draw – Recent Well Results

1

2

3

4

SR 7805AH – 5K Lateral (POL 3/22/19) - 30-Day: 962 Boe/d / 83% oil

SR 9303H – 7.5K Lateral (POL 4/11/19) - Current Rate: 1,264 Boe/d (still increasing) - 10-Day: 1,104 Boe/d / 82% oil (still increasing)

SR 9302H – 7.5K Lateral (POL 4/11/19) - Current Rate: 767 Boe/d (still increasing) - 10-Day: 725 Boe/d / 81% oil (still increasing)

SR 7905AH – 5K Lateral (POL 3/22/19) - 30-Day: 1,042 Boe/d / 84% oil

2-Stream IP Results

1

2

3

4

33

,76

4

34

,34

5

35

,72

7

40

,38

7

43

,93

7

45

,67

8

48

,13

0

33

,50

5

48

,09

1 5

4,2

58

28

,63

7

32

,00

7

33

,08

9

-

10,000

20,000

30,000

40,000

50,000

60,000

Sealy Ranch7902H

Sealy Ranch7701H

Sealy Ranch9301H

Sealy Ranch7702H

Sealy Ranch5902H

Sealy Ranch7903H

Sealy Ranch6401H

Sealy Ranch9305H

Telluride6201H

Trinity6205H

Sealy Ranch8801H

Sealy Ranch8705H

PeerAverage

LongLateral

10

HK’s Monument Draw Peak Month Oil Production vs. Peers (Bbls)

Monument Draw – Excellent First Month Oil Productivity

(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. Includes 284 wells. (2) HK well data based on internal production data and includes all wells for which HK has reached 30 day peak IP rates.

HK’s Peak Monthly Oil Production is 25% Higher than the Peer Average

HK 30-Day Avg. Oil Rate: 39,872 Bbl(2)

(1)

Well Situated with Takeaway and Protected from WAHA Basis Blowout

11

Oil Takeaway

HK is well-positioned with strong takeaway contracts in place and significant basis hedged

• Near-Term Oil Takeaway:

- Vast majority of HK’s oil now on pipe

- 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 mid 2019)

- Pricing likely a premium to NYMEX

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

- 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 majeure)

Note: See further detail of takeaway contracts on slide 18. Does not include impact of NYMEX oil and gas hedges in place.

Waha Basis Hedges in Place (Mmbtu/d)

25,500

-

5,000

10,000

15,000

20,000

25,000

30,000

2019

($1.18) / Mmbtu

Halcón Field Services Overview of Retained Oil & Gas Infrastructure Assets

Area Surface Acreage Gas Gathering, Compression & Treating Crude Gathering and Storage

Monument Draw • 1,665 acres

• 22 miles of sour gas gathering pipelines (8”/16” steel) • 10-15 MMcf/d of treating capacity • 28 MMcf/d of compression • 22 MMcf/d of compression set for delivery May 2019 • Liquid redox Valkyrie system in service

• 27 miles of gathering pipelines (steel ≥8”) • 25,000 bbl/d crude processing capacity • 10,000 bbl crude storage capacity

West Quito Draw • 80 acres •Handled by Crestwood • 3.5 miles of gathering pipelines (12” steel) • 25,000 bbl/d crude processing capacity • 10,000 bbl crude storage facility

Hackberry Draw • 3,074 acres

• 42 miles of gathering pipelines (≥6” steel/poly) • 24 MMcf/d of compression • 24 MMcf/d of treating / compression capacity •Gas sweetening, dehy and JT unit

•Handled by ETC through August 2019 • 6 miles of pipe(≥6” steel)

Monument Draw Infrastructure Hackberry Draw Infrastructure West Quito Draw Infrastructure

Recent Covenant Waiver & Borrowing Base Redetermination

13

• Halcon’s net leverage as of 3/31/19 was above the 5.0x covenant limit as contained in its Senior Revolving Credit Agreement

- Accordingly, HK recently received a waiver on its first quarter 2019 net leverage covenant from its lenders under the revolver

• In connection with our spring redetermination, the Company’s borrowing base was recently redetermined at $225 million

- This was a $50 million reduction from the previous borrowing base level of $275 million

• Halcon and its advisors are currently evaluating strategic and financial alternatives, which includes an evaluation of M&A, recapitalization, and other initiatives

Capitalization & Debt Maturities

14

Capitalization Maturity Schedule

$225

$625

$-

$100

$200

$300

$400

$500

$600

$700

2018 2019 2020 2021 2022 2023 2024 2025 2026

Revolver Senior Notes

Note: As of 5/7/19, HK had $184 million outstanding on its revolver and had $32 million in cash on hand.

Face Value Actual

Capitalization ($MM) 3/31/2019

Cash & Cash Equivalents 0$

Senior Secured Revolving Credit Facility 105

6.75% Senior Unsecured Notes due 2025 625

Total Debt 730$

Total Net Debt / (Cash) 730$

Stockholders' Equity 854

Total Capitalization 1,584$

Borrowing Base(1) 225$

Less: Borrowings (105)

Less: Letters of Credit (2)

Plus: Cash 0

Total Liquidity 118$

(1) Reflects Spring '19 borrowing base redetermination amount

Commodity Hedges

15

Crude Oil (Bbl/d, $/Bbl)

Q2'19 Q3'19 Q4'19 Q2-Q4'19 Q1'20 Q2'20 Q3'20 Q4'20 FY 2020 (3,4)

Costless Collars (Bbl/d) 11,000 12,000 13,000 12,004 4,000 4,000 4,000 4,000 4,000

Ceiling (1) $59.52 $60.56 $60.21 $60.12 $67.00 $67.00 $67.00 $67.00 $67.00

Floor (1) $53.17 $53.57 $53.37 $53.38 $50.13 $50.13 $50.13 $50.13 $50.13

Weighted Average Price (2) $56.34 $57.06 $56.79 $56.75 $58.56 $58.56 $58.56 $58.56 $58.56

Swaps (Bbl/d) 1,816 1,745 1,718 1,760 2,720 2,708 2,681 2,674 2,695

Weighted Average Price $56.80 $56.80 $56.80 $56.80 $57.98 $57.98 $57.99 $58.00 $57.99

Mid-Cush Differential Swap (Bbl/d) 12,000 6,000 4,000 7,316 - - - - -

Basis Swap ($3.97) ($4.94) ($3.95) ($4.23) $ - $ - $ - $ - $ -

Houston-Cush Differential Swap (Bbl/d) - - 5,000 1,673 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)

Q2'19 Q3'19 Q4'19 Q2-Q4'19 Q1'20 Q2'20 Q3'20 Q4'20 FY 2020

Costless Collars (MMbtu/d) 24,000 24,000 24,000 24,000 - - - - -

Ceiling (1) $3.01 $3.01 $3.01 $3.01 $ - $ - $ - $ - $ -

Floor (1) $2.60 $2.60 $2.60 $2.60 $ - $ - $ - $ - $ -

Weighted Average Price (2) $2.81 $2.81 $2.81 $2.81 $ - $ - $ - $ - $ -

WAHA Gas Differential Swap (MMBtu/d) 25,500 25,500 25,500 25,500 - - - - -

Basis Swap ($1.18) ($1.18) ($1.18) ($1.18) $ - $ - $ - $ - $ -

Natural Gas Liquids (Bbl/d, $/Bbl)

Q2 '19 Q3 '19 Q4 '19 Q2-Q4'19 Q1 '20 Q2 '20 Q3 '20 Q4 '20 FY 2020

NGL Swaps (Bbl/d) 4,000 4,000 4,000 4,000 - - - - -

Swap (1) $29.33 $29.33 $29.33 $29.33 $ - $ - $ - $ - $ -

(1) Weighted average price.

(2) Based on average of swap price and midpoint of ceiling / floors of collars.

(3) Excludes 6,400 bbl/d of $70.00 calls.

(4) Floor price includes 2,500 bbls/d of $55/bbl deferred premium puts with a $4.80 premium (i.e. $50.20 effective floor).

Monument Draw Gas Treating Plan

Treating Plan: Reduced wellhead treating given new 3rd 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 beginning of Q2 ’19)

2H ’20 + Beyond 2H ’19 - Q1 ‘19 Q2 ‘19

Treating Plan: Eliminate wellhead chemical treating by utilizing centralized liquid redox treating system (Valkyrie) for sales to Salt Creek Midstream sweet gas line for majority of production, remainder of sour gas sold via ETC/Targa sour gas sales lines

Treating Plan: AGI/Amine facility operational in July/August 2020 and will be used to strip H2S from all gas with 100% of sweet gas sold to Salt Creek Midstream sweet gas

5.00+ per Mcf (1) ~$2.25 – 3.25 per Mcf (1) ~$0.50 - 1.00 per Mcf (1)

Elevated Treating Costs

Lower Treating Cost Than Q1 ‘19

Lowest Cost L-T Solution

(1) Based on gross wellhead gas volumes. Concentration of gas through Valkyrie 30,000-40,000 ppm.

Q3 ’19 – Q2 ‘20

Infrastructure Development: Receive AGI permit in August, begin equipment procurement and construction of AGI/Amine plant from Q3 ’19 – Q2 ’20

Infrastructure Development: Begin front-end engineering and design work, permitting and some reservoir testing on AGI/Amine facility

Appendix

Oil & Gas Marketing & Takeaway

18

Oil

Mar

keti

ng

& T

ake

away

Monument Draw West Quito Draw Hackberry Draw

Gas

Mar

keti

ng

& T

ake

away

- Current:

• 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 (20K bbl/d) with flexibility to scale up or down over time

• Realized pricing likely premium to Midland

- Current:

• 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 premium to Midland

- Current:

• ~95% sold via pipeline and remainder trucked; all sold to Sunoco under a deal that expires in August 2019

• Pricing: Midland less $1.15/bbl

- Aug. ‘19:

• Current gathering deal expires in Aug. ‘19

• Negotiating with several midstream companies to provide oil takeaway options including long-haul optionality

• Realized pricing likely premium to Midland

- Primary Plan:

• Treat gas to remove H2S using Valkyrie and sell to Salt Creek Midstream

• Contract in place through 2032 with Salt Creek Midstream to take wet gas to their processing plant via high pressure pipeline

• Treat gas to remove H2S

• 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 Targa/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 for gas and NGLs that is expandable

• Pricing: Waha less ~$0.03/MMBtu

- Back-up Plan:

• Multiple low pressure sales points with ETC

• Salt Creek Midstream will have high pressure sales connection by end of Q2 ‘19

- 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

Multiple Targets Across All Acreage

19

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

3,6

00

’

3,5

20

’

2,6

30

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

372

447

81

219

58

623

1,177

1,800

3rd BS/WC(Monument)

2 WC Zones(Hackberry)

3rd BS(Hackberry)

2 WC Zones (WestQuito)

3BS (West Quito) Total Base CaseLocations

Additional Locations(All Areas)

Total PotentialLocations

Decades of Drilling Inventory As of March 31, 2019 – 19Q2 Hackberry Expirations Removed

Gross Remaining Operated Locations (1)(2)

Locations by Area

(1) Gross operated locations at 660’ common target spacing in the Wolfcamp per Halcón’s internal estimates. (2) Excludes non-operated locations. (3) Assumes a rig can drill 12 wells per year.

De-risked base case drilling inventory Additional targets

Base Case Inventory Length (Years)(3)

Operated Rigs Running

Gross Locations Net Locations

Monument Draw Hackberry Draw West Quito Draw

33

25 20

16 14

-

10

20

30

40

3 4 5 6 7