Embed Size (px)
Citation preview
Halcón Resources Investor PresentationMay 2018
This communication contains forward‐looking information regarding HalcónResources that is intended to be covered by the safe harbor for "forward‐lookingstatements" provided by the Private Securities Litigation Reform Act of 1995.Forward‐looking statements are based on Halcón Resources’ current expectationsbeliefs, plans, objectives, assumptions and strategies. Forward‐looking statementsoften, but not always, can be identified by words such as "expects", "anticipates","plans", “guidance”, "estimates", "potential", "possible", "probable", or "intends", orwhere 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 inthat they reflect estimates based on certain assumptions, including that the reservesinvolved can be economically exploited. Statements regarding pending acquisitionsand possible dispositions are forward‐looking statements; there can be no guaranteethat acquisitions or dispositions close on the terms or within the timeframedescribed, if at all. Forward‐looking statements are subject to risks and uncertaintieswhich could cause actual results to differ materially from those reflected in thestatements. These risks include, but are not limited to: operational risks in exploringfor, developing and producing crude oil and natural gas; uncertainties involvinggeology of oil and natural gas deposits; the timing of and potential proceeds fromplanned divestitures; uncertainty of reserve estimates; uncertainty of estimates andprojections relating to future production, costs and expenses; potential delays orchanges in plans with respect to exploration or development projects or capitalexpenditures; health, safety and environmental risks and risks related to weathersuch as hurricanes and other natural disasters; uncertainties as to the availability andcost of financing; fluctuations in oil and natural gas prices; risks associated withderivative positions; inability to realize expected value from acquisitions, inability ofour management team to execute our plans to meet our goals; shortages of drillingequipment, oil field personnel and services; unavailability of gathering systems,pipelines and processing facilities; and the possibility that laws, regulations orgovernment policies may change or governmental approvals may be delayed orwithheld. Additional information on these and other factors which could affectHalcón Resources' operations or financial results are included in Halcón Resources’reports on file with the SEC. Investors are cautioned that any forward‐lookingstatements are not guarantees of future performance and actual results ordevelopments may differ materially from those expressed in forward‐lookingstatements. Forward‐looking statements are based on assumptions, estimates andopinions of management at the time the statements are made. Halcón Resourcesdoes not assume any obligation to update forward‐looking statements shouldcircumstances 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, whichare those quantities of oil and gas, which, by analysis of geoscience and engineering data, can beestimated with reasonable certainty to be economically producible—from a given date forward, fromknown reservoirs, and under existing economic conditions (using unweighted average 12‐month firstday of the month prices), operating methods, and government regulations—prior to the time at whichcontracts providing the right to operate expire, unless evidence indicates that renewal is reasonablycertain, regardless of whether deterministic or probabilistic methods are used for the estimation. TheSEC also permits the disclosure of separate estimates of probable or possible reserves that meet SECdefinitions for such reserves. These estimates are by their nature more speculative than estimates ofproved reserves and are subject to greater uncertainties and, accordingly, the likelihood of recoveringthose reserves is subject to substantially greater risks.
We may use the terms “resource potential” and “EUR” in this presentation to describe estimates ofpotentially recoverable hydrocarbons that the SEC rules prohibit from being included in filings with theSEC. These are based on the Company’s internal estimates of hydrocarbon quantities that may bepotentially discovered through exploratory drilling or recovered with additional drilling or recoverytechniques. These quantities do not constitute “reserves” within the meaning of the Society ofPetroleum Engineer’s Petroleum Resource Management System or SEC rules and are subject tosubstantially greater uncertainties relating to recovery than reserves. “EUR,” or Estimated UltimateRecovery, refers to our management’s internal estimates based on per well hydrocarbon quantities thatmay be potentially recovered from a hypothetical future well completed as a producer in the area. Forareas where the Company has no or very limited operating history, EURs are based on publicly availableinformation relating to operations of producers operating in such areas. For areas where the Companyhas sufficient operating data to make its own estimates, EURs are based on internal estimates by theCompany’s management and reserve engineers.
“Drilling locations” represent the number of locations that we currently estimate could potentially bedrilled in a particular area estimated by well spacing assumptions applicable to that area. The actualnumber of locations drilled and quantities that may be ultimately recovered from the Company’sinterests will differ substantially. There is no commitment by the Company to drill the drilling locationswhich have been attributed to any area.
We may use the term “de‐risked” in this presentation to refer to certain acreage and well locationswhere we believe the relative geological risks related to recovery have been reduced as a result ofdrilling operations to date. However, only a small portion of such acreage and locations may have beenattributed proved undeveloped reserves and ultimate recovery from such acreage and locationsremains 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 bedirectly affected by factors that include the availability of capital, drilling and production costs,availability of drilling services and equipment, drilling results, lease expirations, transportationconstraints, regulatory approvals and other factors; and (2) actual drilling results, including geologicaland mechanical factors affecting recovery rates. In addition, our production forecasts and expectationsfor future periods are dependent upon many assumptions, including estimates of production declinerates from existing wells and the undertaking and outcome of future drilling activity, which will beaffected by changes in commodity prices and costs.
Cautionary Statements
Halcón Resources Overview Halcón has built a premier ~60,000 acre position in the Delaware Basin for less than $19,000/net acre (1)
4Note: 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; assumes $59 MM of value attributed to infrastructure assets purchased in Hackberry Draw. (2) Excludes non‐operated locations.
Delaware Basin Overview Total Company Acreage Position
Monument Draw
Hackberry Draw
Total Company:Net Acreage: ~60,216
Operated Potential Gross Drilling Locations (2): 2,055 Current Production: >13,000 Net Boe/d
Monument Draw (Ward County)• Net Acreage: ~22,479 with ~97% average W.I.• 505 gross potential operated drilling locations(2)
• Wolfcamp EURs of ~1.9 MMBoe (~80% oil) assuming 10K’ laterals
West Quito Draw (Ward County)• Net Acreage: ~10,622 with ~72% average W.I.• 407 gross potential operated drilling locations(2)
• Wolfcamp EURs of ~2.2 MMBoe (~50% oil) assuming 10K’ laterals
Hackberry Draw (Pecos County)• Net Acreage: ~27,115 with ~74% average W.I.• 1,143 gross potential operated drilling locations(2)
• Wolfcamp EURs of ~1.5 MMBoe (~75% oil) assuming 10K’ laterals
West Quito Draw
2018 Execution Focused on Development, Delineation & Gaining Scale
5(1) Pro forma to exclude production contribution from Williston Basin non‐op assets sold in early November of 2017.
3
1
76
0 0
2 2
54
12
Q1 '18 Actual Q2 '18 Estimated Q3 '18 Estimated Q4 '18 Estimated
Monument Draw West Quito Draw Hackberry Draw
Gross Wells POL by Quarter
2018 Plan Highlights
Rig Plan‐ Growing to 4 rigs in May ’18
‐ Rigs allocated primarily to Monument and West Quito for 2H‘18
Combination of Development & Delineation Drilling‐ Long lateral development (9,500+ ft.)
‐ Transitioning to multi‐well pad development
‐ Testing upside pay zones (BS, deep targets, etc.)
‐ Optimal spacing tests
‐ Vertical pilot wells
‐ Shuttle logs to determine optimal geo‐steering and frac design
Focus on Efficiencies‐ Focus on reducing drilling days (particularly Monument Draw)
‐ Utilization of a spudder and intermediate rig to reduce drilling costs
‐ Beginning to utilize some local brown sand (i.e. 100 mesh)
‐ Utilize new technologies & techniques to optimize completions
Production Optimization‐ Installation of jet pumps for artificial lift
‐ Removing production bottlenecks
‐ Focus on reducing downtime through proactive maintenance program
Drilling program is weighted toward Monument and West Quito in 2H ‘18
Q4 ’17 to Q4 ’18 Production Growth
5,300
24,000
‐
5,000
10,000
15,000
20,000
25,000
30,000
Production (Boe/d)
(1)Q4 ’18
Estimated
Q4 ‘17
~Significant YOY Growth
Focus on Long Lateral Development
6
Average Completed Lateral Length (CLL)
Production Profile Comparison: 10,000’ vs. 5,000’
0
200,000
400,000
600,000
800,000
1,000,000
0 10 20 30 40 50 60 70
2‐ph
ase Cu
mulative Prod
uctio
n (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 (2H '17 ‐ 1Q '18)(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 4/12/18 strip pricing.
10K Lateral Doubles Production in First 5 Years of Well Life
• Halcón is focused on drilling long laterals in all areas in 2018
• 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: $15 MM
• 5K lateral: $3 MM
‐ IRR(2):• 10K lateral: 68%
• 5K lateral: 28%
$61.59 $59.76
$55.67 $53.73 $53.34
$54.47 $56.38
$66.83
$59.76
$55.67
$61.24 $59.45
$57.81 $56.42
$50.00
$55.00
$60.00
$65.00
$70.00
Q2 '18 Q3 '18 Q4 '18 Q1 '19 Q2 '19 Q3 '19 Q4 '19
Oil Price ($/Bbl)
Midland Forward Prices HK Realized Price (Hedged Production)
Well Protected on Takeaway and Basis Blowout Risk
7
Oil Takeaway Basis Hedges in Place
HK is well‐positioned through 2019 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 Sept. 2018
‐ Pricing of Midland less $0.50 to $1.25/bbl
‐ Very little trucked = lower risk getting oil to market at good prices
• Long‐Term Oil Takeaway:‐ HK is working multiple options to get oil to
gulf coast by late ’18 or early 2019
‐ Pricing likely be premium to NYMEX
Gas Takeaway• Mid‐Cush Oil Basis Hedges:‐ Recently realized ~$30 MM in cash by
monetizing 2H ’18 MidCush hedges and portion of 2019 MidCush hedges
‐ Actively re‐hedging 2H ‘18 and CAL19 to protect from further downside
• Waha Gas Basis Hedges‐ Volume: 10,000 Mmbtu/d from 2H18
through 2019
‐ Pricing: $‐1.05/Mmbtu
• Primary Plan‐ L‐T contracts in place in all areas for Salt
Creek Midstream or ETC to take high pressure wet gas to their processing plants (firm capacity with ETC)
‐ 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
Hedge‐Adjusted Realized Prices ‐ Oil
Note: See further detail of takeaway contracts on slide 19. Does not include impact of NYMEX oil and gas hedges in place. Does not include uplift to pricing if some oil is shipped to gulf coast in 2H ’19.(1) Represents forward pricing levels as of 4/27/18.(2) Reflects HK’s effective realized price adjusted for hedges in place which is calculated as NYMEX forward prices as of 4/24/18 adjusted for average HK hedged price in the period. Does not include
deducts for various takeaway contracts in place. See slide 19 for further detail of takeaway contracts and related fees.
Hedge‐Adjusted Realized Prices ‐ Gas
(1) (2)
(1) (2) (1) (2)
Waha hedges provide HK with a ~$0.42/Mmbtu premium for 2H18
through 4Q19
MidCush hedges provide HK with a ~$5.24/Bbl premium for 2Q’18 &
~4.25/Bbl for FY19 (Valued at ~$22 MM)
$1.52
$1.30 $1.42
$0.92 $1.08
$1.56
$1.76 $1.83 $1.94
$1.52 $1.57 $1.67
$0.75
$1.00
$1.25
$1.50
$1.75
$2.00
Q3 '18 Q4 '18 Q1 '19 Q2 '19 Q3 '19 Q4 '19
Waha Forward Prices HK Realized Price (Hedged Production)
2018 Development Plan – Monument Draw
Well Layout & 2018 Preliminary Drilling Plan Key Considerations
• Vast majority of drilling locations planned to be at 10,000’ CLL or greater
– Units with 15,000’ laterals: 0.5
– Units with 12,500’ laterals: 1
– Units with 10,000’ laterals: 13.5
– Units with 7,500’ laterals: 2
• Expect 20 wells to spud and 17 wells to POL in 2018
– Drilling single wells to maximize production in 2018 and delineate acreage
– Pad development to begin in 2019
2018 Development Plan – Hackberry Draw
Well Layout & 2018 Preliminary Drilling Plan Key Considerations
• Majority of long‐term development planned to be 10,000’ CLL
– Actively working with offset operators to “block up” 1280 acre units to further increase long‐lateral length wells
• Expect 8 wells spud and 12 wells POL in 2018
– All 10,000’ laterals
– Spud: 6 WCB, 1 WCA, 1 BS2
– Combination of delineation drilling, drilling to hold acreage and testing Bone Spring
2018 Development Plan – West Quito Draw
2018 Preliminary Drilling Plan Key Considerations
• Actively working to form units to drill 10,000’ lateral length wells
• Expect 8 wells spud and 4 wells POL in 2018
– All 10,000’ laterals
– Spud: 6 WCA, 2 WCB
– Drilling to hold acreage and satisfy CDC requirements
0
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
11Note: 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 ~38% of NYMEX oil and current D&C costs.
Monument Draw (2‐Stream) 1
West Quito Draw (2‐Stream) 1
D&C: ~$12.5 MM2‐Stream EUR: 1.9 Mmboe (80% Oil, 20% Gas)
2‐Stream 30‐Day Peak IP: ~1,434 boe/d
0
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
0
200
400
600
800
1,000
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 MM2‐Stream EUR : 2.2 Mmboe (50% Oil, 50% Gas)
2‐Stream 30‐Day Peak IP: 2,089 boe/d
D&C: ~$11.0 MM2‐Stream EUR: 1.5 Mmboe (75% Oil, 25% Gas)
2‐Stream 30‐Day Peak IP: 942 boe/d
$7.3
$13.0
$18.7
$24.4
31% 51%
76% 106%
0%40%80%120%160%200%240%
$0.0
$10.0
$20.0
$30.0
$40 $50 $60 $70
IRR (%)
PV‐10 ($MM)
NYMEX Oil ($/bbl)WC PV‐10 WC IRR
$3.2$7.7
$12.2$16.7
19% 34% 51% 72%
0%40%80%120%160%200%240%
$0.0
$10.0
$20.0
$30.0
$40 $50 $60 $70
IRR (%)
PV‐10 ($MM)
NYMEX Oil ($/bbl)WC PV‐10 WC IRR
$2.7$7.3
$11.8$16.3
18% 35% 56% 82%
0%
60%
120%
180%
240%
$0.0
$7.5
$15.0
$22.5
$30.0
$40 $50 $60 $70
IRR (%)
PV‐10 ($MM)
NYMEX Oil ($/bbl)WC PV‐10 WC IRR
Monument Draw WC Performance vs. Type Curve
12
Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with EURs.
Monument Wolfcamp Type Curve (1.9 Mmboe EUR)
Offset Operator Wells
HK Drilled and Completed Wells
Hackberry Draw WC Performance vs. Type Curve
13
Note: See “Cautionary Statements” on page 3 for a discussion on risks associated with EURs.
Hackberry Wolfcamp Type Curve (1.5 Mmboe EUR)
Legacy Operator Wells
HK Drilled and Completed Wells
Legacy wells underperformed type curve from ~50 to ~300 days due to timeliness of artificial lift installations and inefficient gas lift design
First Year Cumulative Oil Production ‐Wolfcamp
14
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
Multiple Targets Across All Acreage
15
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 WolfcampSandsBase 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”.
Decades of Drilling Inventory
16
Gross Remaining Operated Locations (1)(2)
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) Excludes non‐operated locations.(3) Assumes a rig can drill 12 wells per year.
De‐risked base case drilling inventory Additional targets
Inventory Length (Years)(3)
Gross Locations Net Locations
Operated Rigs Running
Monument Draw Hackberry Draw West Quito Draw
5541
33 27 240
20
40
60
3 4 5 6 7
Years Inventory
156139
438
117201
56
948
1,107
2,055
2 WC Zones(Monument)
3rd BS(Monument)
2 WC Zones(Hackberry)
3rd BS(Hackberry)
2 WC Zones (WestQuito)
3BS (West Quito) Total Base CaseLocations
Additional Locations(Monument,
Hackberry & WestQuito)
Total PotentialLocations
505
4071,143
484
302858
Halcón Field Services
17
Cost Benefits of HK‐Owned Water Infrastructure
(1) As of 3/31/18.
AreaSurface Acreage Held (1)
Water Pipelines in Place (1)
Produced Water Capacity (1)
Fresh Water Capacity (1)
Water Storage Capacity(1)
Gas Gathering,Compression & Treating (1)
Monument Draw • 1,625 acres • 27 miles
• 20,000 bwpd of injection (3 wells)
• 40,000 bwpd of recycling (1 facility)
• 10 wells with60,000 bwpd of capacity
• Additional capacity available
• 900,000 bbls of produced/recycled water
• 1,100,000 bbls of fresh water storage
• 22 miles of steel pipe
• 5 MMSCFD• Gas sweetening, dehy and JT unit
West Quito Draw
• Acquiringsurface now
• Construction beginningshortly
• Planning SWD wells now
• Planning fresh water wells now
• Construction beginning shortly
• Handled by Crestwood
HackberryDraw • 3,243 acres • 23 miles
• 45,000 bwpd of injection (3 wells)
• 120,000 bw/d of recycling (3 facilities)
• 4 wells with 40,000 bwpd of capacity
• Additional capacity available
• 2,700,000 bbls of produced/recycledwater storage
• 1,000,000 bbls of fresh water storage
• 28 miles of steel/poly pipe
• 12 MMSCFD• Gas sweetening & dehy and JT unit
$0.18
$0.40 $0.45
$1.00
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
Water Sourcing Costs ($/Bbl) Water Disposal Costs ($/Bbl)
HK‐Owned 3rd Party
Infrastructure Map
Halcón Field ServicesWater Handling and Recycling
18
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 on midstream facilities
• Critical for LOE/GTO cost control
• Since start of operations in Delaware, ~70% of water used for completions (~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 our 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
Oil & Gas Marketing & Takeaway
19
Oil Marketin
g & Takeaway
Monument Draw West Quito Draw Hackberry Draw
Gas M
arketin
g & Takeaway
‐ Current: • All oil sold via truck to single buyer
• Pricing: Midland less ~$1.75/bbl
‐ Projected Sept. 18: • All oil taken to Wink via pipeline constructed by Salt Creek Midstream
• Pricing: Modest discount to Midland
‐ Mid‐2019: • Will have significant long‐haul firm space to Gulf Coast via Epic (20K+ bbl/d) with flexibility to sell in Permian Basin if favorable
• Realized pricing likely at premium to Midland
HK Has Significant Midland and Waha Basis Hedges in Place to Mitigate Near‐Term Basis Blow‐Out Risk
‐ Current: • All oil sold via truck to single buyer
• Pricing: Midland less ~$3.25/bbl
‐ Projected Q3 ‘18: • Negotiating w/ several midstream companies to provide oil takeaway options
• Pricing: Midland less ~$1.00/bbl
‐ Mid‐2019: • Working multiple long‐haul options to dedicate portion of oil production to Gulf Coast
• Realized pricing likely at premium to Midland
‐ Current: • ~70% sold via pipeline and remainder trucked; All sold to Sunoco under long‐term deal that expires in Aug. 19
• Pricing: Midland less ~$1.25/bbl
• By Q4 ’18, expect 75% to be sold via pipeline
‐ Aug. 19: • Current gathering deal expires in Aug. 19
• Negotiating w/ several midstream companies to provide oil takeaway options including long‐haul optionality
• Realized pricing likely at premium to Midland
‐ Primary Plan: • Contract in place through 2032 with Salt Creek Midstream to take wet gas to their processing plant via high pressure pipeline
• Multiple sales outlets from tailgate of plant (El Paso, Comanche Trail and Roadrunner)
• No firm capacity but ample capacity expected
• Pricing: Waha flat
‐ Back‐up Plan: • Multiple low and high pressure sales points with ETC
‐ Primary Plan: • Contract in place through 2027 with ETC to take wet gas to their Arrowhead processing plant via high pressure line
• All pipes at Waha available under this deal
• HK has firm capacity that is expandable
• Pricing: Waha less ~$.03/Mmbtu
‐ Back‐up Plan: • Multiple low pressure sales points with ETC
• Salt Creek Midstream 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(1)
• High pressure wet gas will be delivered to Salt Creek Midstream and taken to their processing plant under same terms as Monument Draw
• Pricing: Waha flat
‐ Back‐up Plan: • Crestwood has several other outlets to move gas to various plants in the Delaware
Full Year 2018 Guidance
20(1) Excludes capitalized G&A.
Q2 2018 Q4 2018 Full Year 2018Production (Boe/d)
Total 13,000 – 14,000 23,000 – 25,000 15,000 – 20,000
% Oil 68% – 72%
% Gas 14% – 16%
% NGL 14% – 16%
Capex(1) ($MM)
D&C Capex $425 ‐ $475
Infrastructure, Seismic and Other Capex $70 – $90
Operating Costs and Expenses ($/Boe)
Lease Operating & Workover $4.25 – $5.25
Gathering, Transportation & Other $3.00 – $4.00
Production Taxes 6% – 7%
Cash G&A $40 ‐ $45 Million
Pro Forma Capitalization
21
Simple capital structure
No near‐term debt maturities
Strong liquidity
‐ $380 MM PF West Quito Draw acquisition
Highlights Pro Forma Capitalization
Halcón has significant liquidity to fund its planned operations
West Pro FormaFace Value Actual Quito Draw Adjusted HKCapitalization ($MM) 3/31/2018 Acquisition 3/31/2018
Cash & Cash Equivalents 382$ (200)$ 182$
Senior Secured Revolving Credit Facility ‐ ‐ 6.75% Senior Unsecured Notes due 2025 625 625 Total Debt 625$ 625$
Total Net Debt / (Cash) 243$ 443$
Stockholders' Equity 1,134 1,134 Total Capitalization 1,759$ 1,759$
Borrowing Base(1) 200$ 200$ Less: Borrowings ‐ ‐ Less: Letters of Credit (2) (2) Plus: Cash 382 182 Total Liquidity 580$ 380$
(1) Borrowing base reflects borrowing base adjusted for Spring 2018 redetermination effective May 1, 2018.
Investment Highlights
22
Significant Inventory
ExcellentGrowth Profile
StrongBalance 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 ~$380 MM • Reasonable leverage profile • 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
Appendix
Commodity Hedges
24
NYMEX Gas Costless Collars
NYMEX WTI Costless Collars
Note: Ceilings and floors reflect weighted average price and FY 2018 reflects Q2 ‘18 through Q4 ’18 hedge positions.
9,000 10,000 13,000 10,673
14,000
$49.01 $48.96 $50.08 $49.43 $52.76
$56.26 $55.98 $56.87 $56.42 $58.77
$25.00$30.00$35.00$40.00$45.00$50.00$55.00$60.00$65.00
‐
5,000
10,000
15,000
20,000
25,000
Q2 '18 Q3 '18 Q4 '18 Q2'18‐Q4'18 FY 2019
Hedged Volume (Bbl/d) Average Floor ($/bbl) Average Ceiling ($/bbl)
7,500 7,500 7,500 7,500 5,000
$3.01 $3.01 $3.01 $3.01
$2.62
$3.30 $3.30 $3.30 $3.30
$3.00
$1.75
$2.25
$2.75
$3.25
‐
5,000
10,000
15,000
20,000
25,000
Q2 '18 Q3 '18 Q4 '18 Q2'18‐Q4'18 FY 2019
Hedged Volume (MMbtu/d) Average Floor ($/MMbtu) Average Ceiling ($/MMbtu)
Basis Hedges
25
WAHA Gas Basis Swaps
Midland WTI Basis Swaps
Note: Ceilings and floors reflect weighted average price and FY 2018 reflects Q2 ‘18 through Q4 ’18 hedge positions.
‐10,000 10,000
6,691 10,000
($1.05) ($1.05) ($1.05) ($1.05)
($1.20)
($1.15)
($1.10)
($1.05)
($1.00)
‐
5,000
10,000
15,000
20,000
25,000
Q2 '18 Q3 '18 Q4 '18 Q2'18‐Q4'18 FY 2019
Hedged Volume (MMbtu/d) Average Basis Swap
8,000 ‐ ‐ 2,647
12,000
($1.27) ($1.27)
($3.02)
($5.50)
($4.50)
($3.50)
($2.50)
($1.50)
‐
5,000
10,000
15,000
20,000
25,000
Q2 '18 Q3 '18 Q4 '18 Q2'18‐Q4'18 FY 2019
Hedged Volume (Bbl/d) Average Basis Swap
Ownership Summary
26
Ownership Summary as of 3/31/18Basic Shares Basic Shares Employee Net Fully Fully Diluted
Holder Outstanding % Ownership Warrants (1) Options (2) Diluted Diluted % OwnershipOther Common Equity Holders 154,379,981 96.2% 4,736,842 0 154,379,981 159,116,823 92.1%Long‐Term Incentive Plan 6,077,937 3.8% 0 7,587,837 6,077,937 13,665,774 7.9%Total 160,457,918 100.0% 4,736,842 7,587,837 160,457,918 172,782,597 100.0%
Note: Net Diluted shares based on 04/24/18 closing stock price of $5.20/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.
