HALCN RESOURCES Company Presentation November 2017 Forward-Looking - - PowerPoint PPT Presentation

HALCÓN RESOURCES

Company Presentation November 2017

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", “forecasts,” “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 dispositions or possible acquisitions and 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 and amount of 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

• r withheld.

Additional information on these and other factors which could affect Halcón Resources'

• perations 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

2

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 of 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 on 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 using 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. This presentation includes the financial measure “Adjusted EBITDA”, which is not in accordance with generally accepted accounting principles (“GAAP”). While management believes that this measure is useful to investors, it should not be used as a replacement for financial measures that are in accordance with GAAP. For additional information, including a reconciliation of Adjusted EBITDA to the nearest comparable measure in accordance with GAAP, please see the appendix.

Cautionary Statements

3

Investment Highlights

Delaware Basin Operator with Significant Inventory Excellent Growth Profile Strong Balance Sheet Compelling Return Profile Attractive Valuation

• 43,719 net acres in the oily window of the Delaware Basin (~75%+ oil)
• 1,750+ gross operated locations
• Manageable HBP requirements
• Pro forma compounded annual production growth of ~250% through 2019
• 2017 financing efforts provide capital to fund growth until cash flow neutrality (early 2020)
• Strong current liquidity ($646 MM)
• Leverage forecast to remain below 1.0x through 2019
• No near-term debt maturities
• Well-level IRRs in excess of 50% at current strip
• Highest capital efficiency of Permian pure-play peer group
• Top-tier field level returns vs. Permian pure-play peer group
• Trading at a significant discount to Permian pure-play peers
• Current share price implies ~$16k/acre valuation vs. ~$41k/acre for peers

Committed and Experienced Team

• Management team has significant equity stake in company
• Technologically focused operations team
• Decades of value creation through M&A&D

4

Acreage Overview

5 Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with drilling locations and EURs. (1) Values production acquired at $35,000 per boe/d; excludes midstream/infrastructure assets purchased. (2) Excludes 280 gross non-operated locations with an average working interest of 6.1%.

Delaware Basin Overview Acreage Position

Monument Draw (Ward County) Hackberry Draw (Pecos County)

Total Company ~43,719 Net Acres 1,755 Drilling Locations (2) Current Production of ~5,500 Boe/d

In less than twelve months, Halcón has built a premier position in the Delaware Basin for ~$19,500/net acre (1)

Hackberry Draw Prospect (Pecos County)

• Net Acreage: ~26,453 with ~73% average W.I.
• 1,138 gross operated drilling locations (2)
• Wolfcamp EURs of 1.1 to 1.3 MMBoe assuming 10,000’ laterals

Monument Draw Prospect (Ward County)

• Net Acreage: ~17,266 with ~100% average W.I.
• 617 gross operated drilling locations
• Wolfcamp EURs of 1.4 to 1.8 MMBoe assuming 10,000’ laterals

0.0x 0.2x 0.4x 0.6x 0.8x 1.0x 1.2x 1.4x Q4 '17 Q1 '18 Q2 '18 Q3 '18 Q4 '18 Q1 '19 Q2 '19 Q3 '19 Q4 '19

Forecasted Leverage (Net Debt/LQA EBITDA) (2)

4,500 17,000 28,000 45,000

2017 PF 2018E 2019E 2020E

Strong But Responsible Growth Plan

Low Leverage and Attaining Cash Flow Neutrality by Late 2019

Q4 ’17 to Q4 ’18 Estimated Production (Boe/d)

6 (2)

~280% ~65%

(1)

~ ~ ~ Leverage is Expected to Remain Below 1.0x

(2)

Projected Cash-Flow Outspend ($MM) (2) Halcón Attains Cash Flow Neutrality By the End of 2019

Note: See “Cautionary Statements” on page 3 for a discussion related to Non-GAAP financial measures. (1) Q4 2017 reflects midpoint of Delaware Basin production guidance; 2017 is pro forma to reflect Delaware Basin assets only. (2) Assumes $55.00 oil and $3.00 gas; 2018 is based on midpoint of guidance assuming a 3.0 rig program; 2019 assumes a 3.0 rig program and similar cost guidance to 2018 with some improvement in LOE and GTO costs on a per boe basis given production growth; 2020 assumes a 5.0 rig program.

Annual Estimated Production (Boe/d)

7,000 22,000

Q4 2017 PF Q4 2018E ~215%

(1)

~ ~

(2)

($70) ($60) ($50) ($40) ($30) ($20) ($10) $0 Q1 '18 Q2 '18 Q3 '18 Q4 '18 Q1 '19 Q2 '19 Q3 '19 Q4 '19

~

~60%

(2)

Balanced Drilling Plan

2018 Drilling Plan Highlights

• Drilling plan is focused on growth, delineation, determining optimal spacing and fulfilling HBP requirements
• Hackberry Draw – one rig for most of 2018

– Managing HBP requirements – Testing Bone Spring – Drilling both WCA and WCB wells

Three Rig Program will Rapidly Grow Scale over the Next Several Quarters

7

Projected Gross Operated Wells Put Online By Quarter

4 5 3 5 3 1 3 5 4 4 Q4 '17 Q1 '18 Q2 '18 Q3 '18 Q4 '18 Hackberry Draw (Pecos) Monument Draw (Ward)

• Monument Draw – two rigs for most of 2018

– Delineating WC zones and Bone Spring across position – Some pad development & spacing tests

~0.8x 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 3.5x 4.0x A B C D E F G H I J K L HK M Future Net Debt / 2018E EBITDA

Leading Capital Efficiency & Leverage vs. Peers

8

Capital Efficiency (2017 to 2018) (1)(2) Estimated Net Debt at Year End 2018 / 2018E EBITDA (2)

Peer Average: ~$40k Peer Average: 1.9x

Note: Dotted black line represents peer average; excludes HK. (1) Calculated as total forecasted capex in 2018 divided by boe/d of production growth from 2017 to 2018; table excludes two peers with no relevant calculation. (2) Peers include JAG, CPE, CDEV, EGN, FANG, PE, RSPP, QEP, CRZO, WPX, SM, PDCE and REN; net debt, capex, production and EBITDA based on consensus forecasts as of 11/7/17. (3) 2017 is pro forma to represent Delaware Basin assets only (~4,500 boe/d); 2018 is based on midpoint of guidance assuming a three rig program (~17,000 boe/d) and $300 MM of D&C capex (midpoint of guidance). (4) Assumes $55.00 oil and $3.00 gas; 2018 is based on midpoint of guidance assuming a three rig program; 2019 also assumes a three rig program and similar cost guidance to 2018 with some improvement in LOE and GTO costs on a per boe basis given production growth.

Halcón Plans to Develop its Acreage with Peer Leading Capital Efficiency While Maintaining Very Low Leverage

~$24k $0 $10,000 $20,000 $30,000 $40,000 $50,000 $60,000 A B C D E F G H I J K HK $ Capex / Boe/d of Production Growth

(3) (4)

~$31 A B C HK D E F G H I J K L M ~$40 30% 40% 50% 60% 70% 80% 90% 100% $24 $26 $28 $30 $32 $34 $36 $38 $40 $42 A B HK C D E F G H I J K L M % Oil Production Revenue/Boe

Compelling Field-Level Operating Margins vs. Peers

9 Note: Total Revenue ($/Boe) excludes the impact of hedging. (1) Peers include JAG, CPE, CDEV, EGN, FANG, PE, RSPP, QEP, CRZO, WPX, SM, PDCE and REN; data per company filings for Q3 2017. (2) HK data based on midpoint of FY 2018 guidance ranges; revenue per boe assumes expected differentials for FY 2018 applied to Q3 ’17 pricing for NYMEX oil and gas. (3) Calculated as total revenue less lease operating expense, workover expense, production taxes and ad valorem and gathering and transportation expense.

Halcón Will Generate Strong Field-Level Returns

Total Revenue ($/Boe) (1)(2) Field-Level Cash Flow ($/Boe) (1)(2)(3)

Peer Average: ~$34/boe & ~59% Oil Peer Average: ~$25/boe

$40,733 $16,247 $19,466 $27,026 $33,869

Permian Pure Play Avg. HK at Current Share Price of $6.85 Implied HK Share Price of $7.79 Assuming Acreage Valued at Cost HK at $10.00 Share Price HK at $12.00 Share Price

Compelling Valuation vs. Peers

10

Halcón Trades at A Significant Discount to Permian Pure-Play Peers on a Value per Acre Basis

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

(1) Based on implied value per acre of peer group calculated as enterprise value as of 11/7/17 less value of current production at $35k per boe/d divided by net Permian acreage. Peers include JAG, CPE, CDEV, EGN, FANG, PE and RSPP. (2) HK enterprise value pro forma for the completed $425 MM senior notes debt repurchase and other announced transactions (see Pro Forma Capitalization); assumes current net Delaware Basin production of ~5,500 boe/d is valued at $35k per boe/d. (3) Implied share price calculated assuming HK’s acreage is valued at actual price paid by HK for acreage.

(2)(3)

Attractive Purchase Price for Core Delaware Basin Acreage

11 (1) Transactions since 7/1/16; data per company investor presentations, press releases and public filings. (2) Transactions assume $35,000 per boe/d for production value; also adjusted to exclude midstream and infrastructure assets.

Select Southern Delaware Transactions (1) $ / Adjusted Net Acre (1)(2)

HK’s average acquisition price of $19,466/acre is significantly below the average price of ~$32,000/acre for other Southern Delaware transactions (2)

$40,571 $34,884 $32,832 $32,019 $31,690 $27,372 $24,845 $19,466 OXY / J. Cleo Silver Run / Centennial CPE / Ameredev PE / APA NE / CWEI FANG / Luxe FANG / Brigham HK / Various Sellers HK / Ward County HK / Pecos County

Hackberry Draw (Pecos County)

Development Plan

Drilling Plan Through 1H 2018

12

• Majority of long-term development planned

to be 10,000’ CLL – Working with offset operators to “block up” 1,280 acre units to increase long- lateral length wells – Combination of delineation drilling, drilling to hold acreage and spacing tests

• 9 wells spud to date with 12 additional wells

planned through 1H 2018 – 20 - 10,000’ laterals – 1 - 5,000’ lateral – 17 WCB, 3 WCA, 1 BS

• 3 wells POL to date with 11 additional wells

to be POL through 1H 2018

Balbo West-Elliot 1H Flowing Back Belle Alexandra 1H WOC Berkley State East 2H Flowing Back Hannah-Johnny 1H Completing Jose-Katie East 1H WOC

Non-Operated Rig HK Operated Rig

Lindsey 1H

woc

Belle Alexandra A 2H Drilling

Halcón Field Services

Hackberry Draw (Pecos County)

13

• 2 produced water recycling facilities, fresh water wells and SWDs

– Each recycling facility has capacity of 40,000 bpd and storage capacity of ~900,000 bbls – Two owned/operated SWD wells have a combined capacity of 30,000 bpd; third SWD being drilled – Production locations connected by pipeline to water facilities – 23 miles of water pipeline installed by year end 2017

• High and low pressure gas systems

– Multiple low pressure gas outlets – Elizabeth HP compression facility will be online Q4 2017 (all gas in the field will be processed and sold from this site) – 27 miles of gas pipeline installed by year end 2017

• Halcón owned power grid has been upgraded to handle power

requirement for the next 2 years – Utility substation is being built in field (will supply all power requirements for the life of the field)

• Field office and equipment yard constructed
• 3,235 surface acres

Overview Map

Monument Draw (Ward County)

Development Plan

Drilling Plan Through 1H 2018

• ~84% of planned locations to be 10,000’ laterals
• 5 horizontal wells spud to date with 11 additional horizontal

wells planned through 1H 2018

– Targeting the Wolfcamp and Bone Spring formations – 2 vertical pilots spud to date

• 1 well POL to date with 9 additional wells to be POL through

1H 2018

• Contiguous acreage footprint provides benefits

– Ideal for multi-well pad development – Maximum efficiency in D&C operations – Simultaneous frac operations maximizes reservoir drainage

14

Sealy Ranch 7701H Sealy Ranch 7702H Sealy Ranch 7703H Drilling Beginning 11/12/17 Sealy Ranch 9301H Completing Sealy Ranch 5902H Drilling

Non-Operated Rig HK Operated Rig

Sealy Ranch 7902H Sealy Ranch 7903H WOC

Halcón Field Services

Monument Draw (Ward County)

15

Overview Map

• Current infrastructure includes freshwater and SWD facilities

– 10 freshwater wells capable of producing 60,000 bpd – Two salt water disposal wells with a combined capacity of 10,000 bpd – 801 surface acres

• Installing 3 phase pipeline to connect locations to a central

production facility – Water will be disposed/recycled from the same facility

• Water recycling facility is currently under construction

– 2 additional SWDs are permitted with total capacity of 30,000 bpd – 23 miles of pipeline installed by year end 2017

• Halcón owned power grid is being built to handle all power

requirements for the life of the field

Recent Southern Delaware Basin Well Results

16

Halcón and Other Operators are Actively Developing the Southern Delaware Basin

Kelley State 22 1H Diamondback IP30/1000’: 123 BOEPD (94% Oil) Balbo-Adrianna 1H Halcon Resources IP30/1000’: 128 BOEPD (70% Oil) Sealy Ranch 79-1H Halcon Resources IP30/1000’: 254 BOEPD (82% Oil) Mendel State 38 1H Diamondback IP30/1000’: 118 BOEPD (87% Oil) Thompson 182W 1H OXY IP30/1000’: 124 BOEPD (78% Oil) Manhattan 183 East 2H OXY IP30/1000’: 133 BOEPD (77% Oil) Manhattan 183 West 1H OXY IP30/1000’: 200 BOEPD (81% Oil) Screaming Eagle 3804H CXO IP30/1000’: 144 BOEPD (83% Oil) Rock River State 30 1H Diamondback IP30/1000’: 189 BOEPD (79% Oil)

9

UL 2932-17 1H Jagged Peak IP30/1000’: 112 BOEPD (84% Oil)

10

UL Rock of Ages 3922-17 1H Felix Energy IP30/1000’: 131 BOEPD (76% Oil)

11

Caprito 99 302H Abraxas Petroleum IP30/1000’: 234 BOEPD (82% Oil)

12

Miami Beach 34-123 2H Cimarex Energy IP30/1000’: 364 BOEPD (82% Oil)

13

Bone Spring

Wolfcamp A Wolfcamp B Permits (last 180 days) Non-Operated Rig HK Operated Rig 1 2 3 4 5 6 7 8

UL 38-17 2H Jagged Peak IP30/1000’: 267 BOEPD (58% Oil)

14

UL 4344-21 1H Jagged Peak IP30/1000’: 143 BOEPD (85% Oil)

15 Halcón’s initial two wells stack up well vs.

• ther wells

in the region

Full Year 2018 Guidance

17

(1) Excludes capitalized G&A.

Full Year 2018

Production (Boe/d)

Total 15,000 – 19,000 % Oil 72% – 78% % Gas 10% – 13% % NGL 12% – 15%

Capex ($MM)

D&C Capex (2) $280 – $320 Infrastructure, Seismic and Other Capex $30 – $40

Operating Costs and Expenses ($/Boe)

Lease Operating & Workover $3.00 – $4.00 Production Taxes 6% – 7% Cash G&A $6.50 – $8.50 Gathering, Transportation & Other $2.00 – $3.00

Differentials (% Before Fees)

% Oil 95% – 99% % Gas 78% – 82% % NGL 40% – 45%

Pro Forma Capitalization

18

 Simple capital structure  No net leverage  No near-term debt maturities  Strong pro forma liquidity (~$646 MM)

Highlights Pro Forma Capitalization Halcón has significant liquidity to fund its planned operations without the need for external financing

Assumed 50% of Williston Basin Exercise of the Face Value Actual HK HY Debt (Non-Op Assets) Monument Draw Adjusted HK Capitalization ($MM) 9/30/2017 Repayment (1) Sale North Option 9/30/2017 Cash & Cash Equivalents 989 $ (438) $ 105 $ (108) $ 549 $ Senior Secured Revolving Credit Facility

• 6.75% Senior Unsecured Notes due 2025

850 (425) 425 Total Debt 850 $ 425 $ Total Net Debt / (Cash) (139) $ (124) $ Stockholders' Equity 1,162 (29) 1,133 Total Capitalization 2,012 $ 1,558 $ Borrowing Base 140 $ (40) 100 $ Less: Borrowings

• Less: Letters of Credit

(6) 3 (3) Plus: Cash 989 549 Total Liquidity 1,123 $ 646 $ (1) 50% of 6.75% Senior Unsecured Notes outstanding redeemed at 103% pursuant to the terms of the amended indenture.

Appendix

558 343 580 274 1,755

WCA, WCB, & 1st Bone Spring (Pecos) WCA, WCB & 3rd Bone Spring (Ward) Lower WCA, Avalon, 2nd & 3rd Bone Spring (Pecos) Avalon, 1st & 2nd Bone Spring (Ward) Total Locations

Decades of Drilling Inventory

20

Gross Remaining Operated Locations (1)(2) Multi-Bench Inventory (Hackberry Draw Assets)

Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with drilling locations. (1) Gross Operated Locations per Halcón’s internal estimates. (2) Excludes 280 gross non-operated locations with an average working interest of 6.1%.

5,280’

4 Wells / Section 4 Wells / Section 8 Wells / Section 7 Wells / Section

WC A 3rd Bone Spring Avalon 1st Bone Spring 2nd Bone Spring WC A Lower

Near Term Drilling (WCA, WCB, 1st Bone Spring)

8 Wells / Section

WC B

Additional Upside potential in WCA Lower, Avalon, 2nd & 3rd Bone Spring

4 Wells / Section 4 Wells / Section

Near to medium term drilling plan Future drilling and upside

79% Avg. W.I.; 53% 10K Ft. Development 100% Avg. W.I.; 79% 10K Ft. Development 79% Avg. W.I.; 54% 10K Ft. Development 100% Avg. W.I.; 77% 10K Ft. Development

Hackberry Draw (Pecos County)

Offset Drilling Activity

21 Note: EUR Boe/ft based on internal HK estimates.

# Halcon POL Date Boe/Ft 1 BALBO-ADRIANNA WEST 1H 7/30/2017 137 2 BARBARA STATE 1H 9/1/2016 120 3 DONNA STATE EAST UNIT 1H 8/7/2016 146 4 DONNA STATE WEST UNIT 1H 8/5/2016 127 5 BALBO EAST UNIT 1H 4/28/2016 126 6 BALBO SOUTHEAST UNIT 1H 3/17/2016 147 7 BERKLEY STATE WEST UNIT 1H 2/26/2016 102 8 FAYE WEST UNIT 1H 2/4/2016 146 9 BALBO WEST UNIT 1H 2/2/2016 119 10 GENEVA EAST UNIT 1H 11/8/2015 148 11 ADRIANNA 1H 9/16/2015 140 12 BERKLEY STATE EAST UNIT 1H 7/30/2015 53 13 CONNIE 1H 6/12/2015 122 # Contago / Crimson POL Date Boe/Ft 14 RUDE RAM 2120 1H OH 4/26/2017 76 15 RIPPER STATE 1924 1H 4/25/2017 51 16 LONESTAR GUNFIGHTER 1813 1H 2/1/2017 53 # CXO POL Date Boe/Ft 17 SCREAMING EAGLE UNIT 3804H 9/1/2016 136 18 PHOENIX UNIT 7601H 7/1/2016 101 19 LARIMER STATE UNIT 6202H 2/1/2016 87 20 CIMARRON 3702H 1/1/2016 167 # Diamondback POL Date Boe/Ft 21 MENDEL STATE 38 1H 1/1/2017 125 22 ROCK RIVER STATE 30-31 1H 1/1/2017 292 23 LETHCO NEAL 18 1H 9/1/2016 107 24 LETHCO NEAL 35-36 1H 7/1/2016 132 25 TYTEX 41-42 1H 7/1/2016 103 26 MCCOMBS STATE 1-12 2H 6/1/2016 137 27 MCINTYRE STATE 38 1H 6/1/2016 102 28 SABINE 10S-2 1H 6/1/2016 150 29 STEWART 28-21 1H 3/1/2016 140 30 KELLEY STATE 22 1H 1/1/2016 113 31 OATES 10N-2 1H 1/1/2016 137 32 BINKLEY 37 1H 9/1/2015 201 33 ZAUK 39 1H 6/1/2015 101 # Manti Tarka POL Date Boe/Ft 34 SMARTY JONES STATE 32 SOUTH 1HA 1/1/2016 111 # NBL Permian POL Date Boe/Ft 35 COLLIER 34-51 1H 7/1/2016 253 # Oxy POL Date Boe/Ft 36 MANHATTAN 183E 2H 3/1/2017 95 37 MDJ CALDWELL C 21NH 3/1/2017 103 38 THOMPSON 182W 1H 3/1/2017 162 39 MANHATTAN 183 WEST 1H 2/1/2017 130 40 MDJ CALDWELL N 15NH 11/1/2016 85 41 AGATE 179 NORTHEAST 1H 8/1/2016 107 42 BIG GEORGE 180 1H 8/1/2016 88 43 BIG GEORGE 180 3H 6/1/2016 66 44 IRON MIKE 40 SOUTHWEST 4H 4/1/2016 154 45 IRON MIKE 40 NORTHWEST 3H 2/1/2016 165 46 IRON MIKE 40 NORTHEAST 1H 1/1/2016 110 47 FARADAY 23 NORTHWEST 1H 11/1/2016 133

The average BOE per lateral foot for Wolfcamp A & B wells recently drilled is 128 BOE/ft

Offset Activity

Hackberry Draw (Pecos County)

Asset Overview

North and South Prospects

22

Key Considerations

• Hackberry Draw North

– ~80% of acreage and locations – Successful horizontal Wolfcamp development across acreage – Higher working interest units – Deeper and higher pressure

• Hackberry Draw South

– ~20% of acreage and locations – Very few wells drilled on or offsetting position – Lower working interest units – Shallower and lower pressure

• Wolfcamp Deep Project

– 500’ to 1,500’ below horizontal Wolfcamp targets – Sandstone targets (better porosity and permeability) – 3D used to identify targets – Could drill vertically or horizontally

Hackberry Draw North ~21,043 Net Acres Hackberry Draw South ~5,410 Net Acres

Wolfcamp Deep Project

Improving Pecos County Drilling Efficiencies

23

33.78 30.50 27.29 22.88

5 10 15 20 25 30 35 40

Days 3 wells 1 well (Lindsey 1H) 3 wells

Halcon Q2 2017 Halcon Q3 2017 Prior Operator Previous Results All 10k’ Laterals

3 wells

Halcon Q4 2017

Hackberry Draw 10,000’ Lateral Wells Average Intermediate Spud to Rig Release Cycle Times

200 400 600 800 1,000 1,200 1,400 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 (Pecos County)

Type Curves (10,000’ Lateral)

Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with EURs. (1) Assumes a $3.00/MMBtu gas price and NGL pricing of ~37% of NYMEX oil.

Wolfcamp A Type Well Wolfcamp B Type Well WCB Economics at Flat WTI Pricing (1)

24

• Avg. EUR: 1,142 Mboe

Boe/ft: 114 D&C: ~$9.7 MM 30-Day Peak IP: ~1,200 boe/d

• Avg. EUR: 1,312 Mboe

Boe/ft: 132 D&C: ~$9.7 MM 30-Day Peak IP: ~1,630 boe/d

WCA Economics at Flat WTI Pricing (1)

$3.9 $7.7 $11.6 $15.4 24% 42% 65% 92% 0% 40% 80% 120% 160% 200% $0.0 $4.0 $8.0 $12.0 $16.0 $20.0 $40 $50 $60 $70 IRR (%) PV-10 ($MM) NYMEX Oil ($/bbl) WC A PV-10 WC A IRR $5.5 $9.5 $13.6 $17.7 33% 57% 87% 127% 0% 40% 80% 120% 160% 200% $0.0 $4.0 $8.0 $12.0 $16.0 $20.0 $40 $50 $60 $70 IRR (%) PV-10 ($MM) NYMEX Oil ($/bbl) WC B PV-10 WC B IRR 200 400 600 800 1,000 1,200 1,400 1,600 1,800 1 3 5 7 9 11 13 15 17 19 21 23 25 27 Normalized Rate (Boe/d) Normalized Time (Months)

100 1,000 1 11 21 31 41 51 61 71 81 Bbl/d Days Online (Downtime Removed) Faye West Unit 1H Oil Ethel-Jesper 1H Oil 100 1,000 1 76 151 226 301 376 451 526 601 676 Bbl/d Days Online (Downtime Removed) Faye West Unit 1H Oil WC B Oil Type Curve

Ethel-Jesper East 1H (WC A) Well Performance

25

Well Performance (Oil Only) vs. Faye West Unit 1H

The Ethel-Jesper Well’s Early Performance is Slightly Better than the Offsetting Faye West Unit 1H (EUR >1.2 MMBoe)

Faye West Unit 1H (Oil Only) vs. WC A Type Curve

(1)

Well Location

Data Faye West Unit 1H Ethel-Jesper East 1H First Production: 2/5/16 9/27/17 CLL: 8,509’ 9,402’ 2-Stream Peak 24 Hour IP (Boe/d) 714 1,344 % Oil 80% 87% EUR (Boe/ft): 146 TBD Total EUR (MBoe) 1,242 TBD Note: Difference in first days of production due to choke management. (1) Faye West Unit 1H production normalized to 10,000’ CLL. Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with EURs; Faye West Unit 1H and the Ethel-Jesper East 1H were completed with 2,217 and 2,277 (lbs/ft), respectively.

Monument Draw (Ward County)

Asset Overview

26 Note: EUR Boe/ft based on internal HK estimates.

Acreage Position and Offset Activity

• 17,266 total net acres

– Avg. W.I. 100% with NRI of 74.6%

• Monument Draw South (8,946 Net Acres)

– Successfully tested vertical well – 1st horizontal well (CRMWD 79-1H) put online in May 2017

• Peak 30-day average rate of 1,343 boe/d (2 stream ~81% oil)
• Still producing ~1,000 boe/d after 150+ days online
• ~5,200’ lateral; 35 stages; 2,500 lbs/lateral foot of proppant

– Exercised option in June 2017

• Monument Draw North (8,320 Net Acres)

– Drilled a vertical well; currently evaluating log data – Currently completing 1st horizontal well – Expect to exercise option prior to 12/31/17

• Proximity to the Central Basin Platform allows for two

additional targets (Barnett and Woodford) across portions of the acreage position

Ward County Acreage

HK CRMWD 79-1H 5,200’ 150-day IP: 1,100 boe/d

The average BOE per lateral foot for Wolfcamp A & B wells recently drilled in area is 135 BOE/ft

Non-Operated Rig HK Operated Rig

Monument Draw North 8,320 Net Acres Monument Draw South 8,946 Net Acres

# Operator Well POL Date Boe/Ft 1 Halcon CRMWD-79 1H 11/1/2016 217 2 Abraxas CAPRITO 99 302H 11/1/2016 146 3 Cimarex MIAMI BEACH 34-123 2H 1/1/2017 299 4 Felix UNIVERSITY 24-17 1H 4/1/2015 86 5 Jagged Peak RK-UTL 3031A-17 1H 12/1/2016 148 6 Jagged Peak RK-UTL 3031B-17 1H 12/1/2016 102 7 Jagged Peak UTL L J BELDIN 1211-17 3H 10/1/2016 145 8 Jagged Peak UTL 2932-17 1H 7/1/2016 152 9 Jagged Peak UTL 2635-17 1H 4/1/2016 124 10 Jagged Peak UTL L J BELDIN 1211-17 2HX 12/1/2015 98 11 Jagged Peak UTL 28-17 1H 6/1/2015 135

200 400 600 800 1,000 1,200 1,400 1,600 1,800 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) 200 400 600 800 1,000 1,200 1,400 1,600 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 Normalized Rate (Boe/d) Normalized Time (Months)

Monument Draw (Ward County)

Type Curves (10,000’ Lateral)

Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with EURs. (1) Assumes a $3.00/MMBtu gas price and NGL pricing of ~37% of NYMEX oil.

Wolfcamp – Monument Draw South – Type Well Wolfcamp – Monument Draw North – Type Well WC – Monument Draw North – Flat WTI Pricing (1)

27

• Avg. EUR: 1,848 Mboe

Boe/ft: 185 D&C: ~$10.5 MM 30-Day Peak IP: ~1,780 boe/d

• Avg. EUR: 1,432 Mboe

Boe/ft: 143 D&C: ~$10.5 MM 30-Day Peak IP: ~1,380 boe/d

WC – Monument Draw South – Flat WTI Pricing (1)

$10.6 $16.2 $21.8 $27.3 52% 89% 135% 183% 0% 40% 80% 120% 160% 200% $0.0 $6.0 $12.0 $18.0 $24.0 $30.0 $40 $50 $60 $70 IRR (%) PV-10 ($MM) NYMEX Oil ($/bbl) WC PV-10 WC IRR $6.2 $10.7 $15.2 $19.7 34% 53% 83% 112% 0% 40% 80% 120% 160% $0.0 $6.0 $12.0 $18.0 $24.0 $40 $50 $60 $70 IRR (%) PV-10 ($MM) NYMEX Oil ($/bbl) WC PV-10 WC IRR

Hedging Summary

28

Crude Oil (Bbl/d, $/Bbl) Q4 '17 FY 2017(3) Q1 '18 Q2 '18 Q3 '18 Q4 '18 FY 2018 Q1 '19 Q2 '19 Q3 '19 Q4 '19 FY 2019 Costless Collars (Bbl/d) 5,413 5,413 8,000 9,000 10,000 11,000 9,510 4,000 3,000 3,000 3,000 3,247 Ceiling (1) $62.90 $62.90 $56.82 $56.26 $55.98 $55.95 $56.21 $54.24 $55.07 $55.07 $55.07 $54.81 Floor (1) $55.13 $55.13 $49.29 $49.01 $48.96 $49.11 $49.08 $49.24 $50.07 $50.07 $50.07 $49.81 Weighted Average Price (2) $59.02 $59.02 $53.05 $52.63 $52.47 $52.53 $52.65 $51.74 $52.57 $52.57 $52.57 $52.31 Mid-Cush Differential Swap (Bbl/d) 7,000 8,000 13,500 13,500 10,526 12,000 12,000 12,000 12,000 12,000 Basis Swap $ - $ - ($1.29) ($1.27) ($1.21) ($1.21) ($1.23) ($1.02) ($1.02) ($1.02) ($1.02) ($1.02) Natural Gas (MMBtu/d, $/MMBtu) Q4 '17 FY 2017(3) Q1 '18 Q2 '18 Q3 '18 Q4 '18 FY 2018 Q1 '19 Q2 '19 Q3 '19 Q4 '19 FY 2019 Costless Collars (MMbtu/d) 5,000 5,000 7,500 7,500 7,500 7,500 7,500 Ceiling (1) $3.76 $3.76 $3.30 $3.30 $3.30 $3.30 $3.30 $0.00 $0.00 $0.00 $0.00 $0.00 Floor (1) $3.26 $3.26 $3.01 $3.01 $3.01 $3.01 $3.01 $0.00 $0.00 $0.00 $0.00 $0.00 Weighted Average Price (2) $3.51 $3.51 $3.16 $3.16 $3.16 $3.16 $3.16 N/A N/A N/A N/A N/A (1) Weighted average price. (2) Based on average of swap price and midpoint of ceiling / floors of collars. (3) Remaining 3 months of 2017.

Ownership Summary

29

Ownership Summary Basic Shares Basic Shares Employees Net Fully Fully Diluted Holder Outstanding % Ownership Warrants (1) Options (2) Diluted Diluted % Ownership Other Common Equity Holders 145,179,981 97.0% 4,736,842 145,179,981 149,916,823 93.0% Long-Term Incentive Plan 4,416,086 3.0% 6,856,571 4,416,086 11,272,657 7.0% Total 149,596,067 100.0% 4,736,842 6,856,571 149,596,067 161,189,480 100.0% Note: Net Diluted shares based on 11/07/17 closing stock price of $6.85/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.

Non-GAAP Adjusted EBITDA Reconciliation

30

Adjusted EBITDA Reconciliation ($000s)

Note: See “Cautionary Statements” on page 3 for a discussion related to Non-GAAP financial measures. (1) Adjusted EBITDA is a non-GAAP measure, which is presented based on management's belief that it will enable a user of the financial information to understand the impact of these items on reported

• results. Additionally, this presentation provides a beneficial comparison to similarly adjusted measurements of prior periods. This financial measure is not a measure of financial performance under

GAAP and should not be considered as an alternative to GAAP. This financial measure may not be comparable to similarly named non-GAAP financial measures that other companies may use and may not be useful in comparing the performance of those companies to Halcón's performance. (2) For illustrative purposes, the Company has combined the Successor and Predecessor results to derive combined results for the three and nine-month periods ended September 30, 2016. The combination was generated by addition of comparable financial statement line items. However, because of various adjustments to the consolidated financial statements in connection with the application of fresh-start reporting, including asset valuation adjustments and liability adjustments, the results of operations for the Successor may not be comparable to those of the Predecessor. The financial information preceding the table above provides the Successor and the Predecessor GAAP results for the applicable periods. The Company believes that subject to consideration of the impact

• f fresh-start reporting, combining the results of the Predecessor and Successor provide meaningful information about, for instance, production, revenues and costs, that assist a reader in

understanding the Company’s financial results for the applicable periods. Three Months Ended September 30, Nine Months Ended September 30, 2017 2016 (2) 2017 2016 (2) Net income (loss), as reported 419,287 $ 475,568 $ 628,816 $ (438,734) $ Impact of adjusting items: Interest expense 21,394 26,863 66,141 129,351 Depletion, depreciation and accretion 35,940 34,669 100,788 129,606 Full cost ceiling impairment

• 420,934
• 1,175,703

Other operating property and equipment impairment

• 28,056

Income tax provision (benefit) (17,000) (5,309) (5,000) (5,309) Share-based compensation 12,258 14,420 33,548 18,072 Interest income (693) (13) (851) (33) (Gain) loss on sale of other assets (358) 592 (355) 430 Restructuring 1,275 95 2,080 5,168 Reorganization items

• (913,166)
• (913,166)

Loss (gain) on extinguishment of debt 29,167

• 86,065

(81,434) (Gain) loss on sale of oil and natural gas properties (491,830)

• (727,520)
• Loss (gain) on mark-to-market of embedded derivative and tranche rights
• (8,754)
• (5,734)

Unrealized loss (gain) on derivatives contracts 31,209 69,789 (11,010) 294,070 Write-off of deferred loan costs

• 2,917

305 3,582 Rig termination / stacking charges 1,256 3,003 5,859 9,464 Transaction costs, key employee retention agreements and other 12,609 6,342 14,015 37,883 Adjusted EBITDA(1) 54,514 $ 127,950 $ 192,881 $ 386,975 $

Contact Information Quentin Hicks SVP – Finance and Investor Relations 832.538.0557 qhicks@halconresources.com