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

SLIDE 1

Halcón Resources Investor Presentation November 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: ~56,934 Operated Potential Gross Drilling Locations: 1,898 Current Production: ~17,500 Net Boe/d (~70% oil)

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

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

West Quito Draw

SLIDE 5

Recent Achievements

5

Achievement Commentary Successful Infrastructure Sale ‐ Raised $200 MM through water infrastructure sale ($325 MM total valuation) ‐ 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 Continued Strong Well Results ‐ Five new wells in MD with an avg. 30‐day peak IP rate of 1,753 Boe/d (80% oil)(2) ‐ 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)

Contracted Firm Oil Takeaway ‐ 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)

Good Q3 2018 Execution ‐ 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.

SLIDE 6

Halcón’s Strategic Rationale for the Midstream Transaction

Transaction Enables HK to Achieve Several Strategic and Financial Objectives

Demonstrate the Embedded Value

• f Midstream

Operations Generate Proceeds to Enhance Leverage and Liquidity Position Focus on Accelerating Upstream Development Retain Economic Interest in the Growing Oil & Gas Midstream Operations Provide Firm Capacity for Future Water Handling Needs with Reputable Party

6

SLIDE 7

29 26 23 20 25 24 22 18 ‐ 5 10 15 20 25 30 35 Previous Operator Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 ‐ Record Well Days, Int. spud to TD Faye‐Faye West 1H

Near‐Term Drilling Plan

Focused on Efficiencies & Gaining Scale

7

Near‐Term Plan Highlights

3 Operated Rigs Running ‐ 1 rig in each area ‐ 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

Monument Draw Drilling Efficiencies Benefits of Jet Pump Installation

9.1 17.4 12.0 7.4 4.7

‐ 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0 20.0

3Q17 4Q17 1Q18 2Q18 3Q18 Days, 1st Intermediate Spud to RR RECORD

Hackberry Draw Drilling Efficiencies

Flowing Jet Pump

SLIDE 8

Attractive Break‐Even Well Economics

$ / Bbl Attractive Break‐Even Economics(1)

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.

(2)

8

SLIDE 9

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)

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

Monument Draw – Recent Well Results

9

1 2 3 4 5 6 9 7 8

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 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

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

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

2‐Stream IP Results

1 2 3 4 5 6

SR 7506H (POL 9/22/18)

‐ Cut oil Oct 5; Shut‐in in Mid‐Oct. given gas treating constraints

9

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

7

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

8

SLIDE 10

33,764 34,345 35,727 40,387 43,937 45,678 48,130 33,505 48,091 54,258 33,367 ‐ 10,000 20,000 30,000 40,000 50,000 60,000 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

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. (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: 41,782 Bbl(2)

(1)

SLIDE 11

Monument Draw ‐ Spacing Test Support

Spacing Test Pad Overview 7701H and 7702H Microseismic 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
• f 330’ stagger/stacked horizontal

spacing Historical Spacing Tests Program & Results

• HK has successfully demonstrated its ability to decrease spacing without experiencing parent‐child interference

11

SLIDE 12

Hackberry Draw ‐ Spacing Test Support

Spacing Test Pad Overview Belle Alexandra Microseismic Results

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 3rd 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 3rd BS

– Supports potential to tighten spacing

Bailey 3H & 4H (currently flowing back after frac)

• Testing 660’ spacing
• WC A Lower target

Historical & Future Spacing Test Programs

12

SLIDE 13

West Quito ‐ Draw Shuttle Log

HK is Planning to Rapidly De‐Risk West Quito Draw and Early Data is Very Positive

13

SLIDE 14

Upside Development Targets Lateral Development Targets

Monument Draw ‐ Inventory Summary

Development Inventory Summary (Gross) 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 2018.

Stacked Reservoirs Provide Significant Development Inventory and Upside Opportunity

Monument Draw Type Log

Wolfcamp Bone Spring Avalon

1st 2nd 3rd

4

4 4 7

74

74 74 Total: 588 35

Wells / DSU(1) Remaining Inventory(2)

108 8 110 8 148 Upside Development Targets Lateral Development Targets

14

SLIDE 15

West Quito Draw ‐ Inventory Summary

Development Inventory Summary (Gross)

• Development plan locations are based on the area’s geologic prospectivity and

local offset development activity

• ~17,600 gross acres for development
• Contiguous acreage provides for full development of 10,000 foot lateral lengths

at 660 foot spacing Inventory Derivation Methodology

Tremendous Upside Potential in Undeveloped Bone Spring and Avalon Formations

Upside Development Targets Lateral Development Targets Bone Spring Avalon

1st 2nd 3rd

Wolfcamp

AU AL B

1. Chart represents a fully developed 1,280 acre unit 2. Well count represents total inventory remaining for each bench as of August 2018

West Quito Draw Type Log

4

4 4 4 8 7 8

50

50 50 58 44 61 96 Total: 409 39

Wells / DSU(1) Remaining Inventory(2)

Upside Development Targets Lateral Development Targets

15

SLIDE 16

Development Inventory Summary (Gross)

• Development plan locations are based on the area’s geologic prospectivity and

local offset development activity

• ~31,250 gross acres for development
• Contiguous acreage provides for full development of 10,000 foot lateral lengths

at 660 foot spacing Inventory Derivation Methodology

Upside Development Targets Lateral Development Targets

Thick Bone Spring and Wolfcamp Reservoirs Allow for Stacked Lateral Development

Hackberry Draw Type Log

Bone Spring Avalon

1st 2nd 3rd

Wolfcamp

AU AL B

1. Chart represents a fully developed 1,280 acre unit 2. Well count represents total inventory remaining for each bench as of October 2018

4

4 4 4 8 7 8

94

94 93 93 187 165 175 Total: 901 39

Wells / DSU(1) Remaining Inventory(2)

Hackberry Draw ‐ Inventory Summary

Upside Development Targets Lateral Development Targets

16

SLIDE 17

Well Situated with Takeaway and Protected from Basis Blowout

17

Oil Takeaway HK is well‐positioned 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 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 a premium to NYMEX

Gas Takeaway

• Primary Plan

‐ L‐T firm commitment contracts in all areas for third party midstream

• perators 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)

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)

14,000 5,000 ‐ 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000

1H 2019 2H 2019

($3.58) / Bbl ($4.54) / Bbl 25,500 ‐ 5,000 10,000 15,000 20,000 25,000 30,000

2019

($1.18) / Mmbtu

SLIDE 18

Halcón Field Services

Overview of Retained Oil & Gas Infrastructure Assets

18

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

SLIDE 19

Capitalization & Debt Maturities

19

Pro Forma Capitalization  Simple capital structure  No near‐term debt maturities  Strong pro forma liquidity of $418 MM Maturity Schedule

$275 $625 $‐ $100 $200 $300 $400 $500 $600 $700 2018 2019 2020 2021 2022 2023 2024 2025 2026

Senior Revolver Senior Notes

Water Face Value Actual Infrastructure Pro Forma Capitalization ($MM) 9/30/2018 Monetization(2) 9/30/2018 Cash & Cash Equivalents ‐ $ 145 $ 145 $ Senior Secured Revolving Credit Facility 55 ‐ 6.75% Senior Unsecured Notes due 2025 625 625 Total Debt 680 $ 625 $ Total Net Debt / (Cash) 680 $ 480 $ Stockholders' Equity 1,046 1,046 Total Capitalization 1,726 $ 1,671 $ Borrowing Base 200 $ 75 $

(1)

275 $ Less: Borrowings (55) 55 ‐ Less: Letters of Credit (2) (2) Plus: Cash ‐ 145 145 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 2018.

SLIDE 20

Q4 2018 Guidance

20

(1) Excludes capitalized G&A.

Q4 2018

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

SLIDE 21

Commodity Hedges

21 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)

SLIDE 22

Investment Highlights

22

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

• ~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
• Q4 ’17 to Q4’18 expected production growth in excess of 250%
• Significant long‐term growth potential
• Strong current liquidity of ~$418 MM (pro forma for water infrastructure sale and revised borrowing

base)

• No near‐term debt maturities
• 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 23

Appendix

SLIDE 24

Oil & Gas Marketing & Takeaway

24

Oil Marketing & Takeaway

Monument Draw West Quito Draw Hackberry Draw

Gas Marketing & Takeaway

‐ Current:

• 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

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 ~$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

‐ 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 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

‐ 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
• ur gas and NGLs
• 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 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 ‐ 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

SLIDE 25

Multiple Targets Across All Acreage

25

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 26

Decades of Drilling Inventory

Gross Remaining Operated Locations (1) Locations by Area

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

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.

366 527 93 201 58 653 1,245 1,898

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

53 40 32 26 23 ‐ 10 20 30 40 50 60 3 4 5 6 7

26

SLIDE 27

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

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.

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

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: ~$11.5 MM 2‐Stream EUR : 2.2 Mmboe (50% Oil, 50% Gas) 2‐Stream 30‐Day Peak IP: 2,089 boe/d D&C: ~$10.9 MM 2‐Stream EUR: 1.5 Mmboe (75% Oil, 25% Gas) 2‐Stream 30‐Day Peak IP: 942 boe/d

SLIDE 28

Monument Draw WC Performance vs. Type Curve

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

Monument Wolfcamp Type Curve (1.9 Mmboe EUR)

SLIDE 29

First Year Cumulative Oil Production ‐ Wolfcamp

29

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 30

Monument Draw Gas Treating Plan

Treating Plan: Treat gas at the wellhead via bubble towers with chemicals for sales to sweet gas line

• r 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

Long‐Term Lower Cost Solutions on Track for Operation in Q2‐Q3 2019

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 by end of Q1 ’19)

Q3 ‘18 2H ’19 + Beyond Q4 ‘18 – Q1 ‘19 Q2 ‘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 / $8.00 ‐ 10.00 per Mcf (1) Q1 ’19: $3.5 ‐ 4.5 MM / $3.75 ‐ 5.00 per Mcf (1) ~$1.75 ‐ 2.25 per Mcf (1) ~$0.50 ‐ 1.00 per Mcf (1)

30

Highest Cost Lower Cost Lower Cost Lowest Cost L‐T Solution

(1) Based on gross wellhead gas volumes.

SLIDE 31

Ownership Summary

31

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 153,983,097 95.9% 4,736,842 153,983,097 158,719,939 91.8% Long‐Term Incentive Plan 6,616,756 4.1% 7,476,471 6,616,756 14,093,227 8.2% Total 160,599,853 100.0% 4,736,842 7,476,471 160,599,853 172,813,166 100.0% 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.