Title of Presentation
2014 DUG Eagle Ford A New Eagle Ford Core Area: The El Halcón Field Charles Cusack III, EVP & COO September 16, 2014
Forward-Looking Statements
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 using words such as "expects", "anticipates", "plans", "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 resources involved can be economically exploited. Forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to: operational risks in exploring for, developing and producing crude oil and natural gas; uncertainties involving geology of oil and natural gas deposits; the timing of and potential proceeds from planned divestitures; uncertainty of reserve estimates; uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters; uncertainties as to the availability and cost of financing; fluctuations in oil and natural gas prices; risks associated with derivative positions; inability to realize expected value from acquisitions, inability of our management team to execute 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' pro forma 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 the projections in the 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 estimates or opinions change. 2
Cautionary Statements
The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible— from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves, however, we currently do not disclose probable or possible reserves in our SEC filings. 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. “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 all of the drilling locations which have been attributed these quantities. 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 may be affected by significant commodity price declines or drilling cost increases. 3
Company Profile Significant Resource Opportunity Total Proved Reserves: (1)
Bakken/Three Forks ~131,000 Net Acres
119.6 MMBoe
% Proved Developed:
41%
% Oil:
84%
% Operated:
92%
90.4 MMBoe Proved Reserves (1)
Other 6.5 MMBoe Proved Reserves (1)
Total Proved PV10: (1)
$2,317 MM
Net Unrisked Resource Potential: (2) 2Q14 PF Net Daily Prod: (1)
~1.3 BBoe 40,396 Boe/d
El Halcón ~101,000 Net Acres 22.7 MMBoe Proved Reserves (1)
TMS ~316,000 Net Acres
Note: See “Cautionary Statement Regarding Hydrocarbon Quantities” on page 3 for a description of resource potential.
(1)
(2)
Proved reserves and PV10 as of 12.31.13 as estimated by Halcón’s independent reserve engineers using unweighted average first-day-of-the-month commodity prices for the year ended 12.31.13 and in accordance with SEC rules relating to reporting of reserves; Proved reserves, PV10 , 2Q14 and current production pro forma to exclude non-core assets in East Texas and Eastern Montana sold in 2Q14. Net unrisked resource potential calculated by Halcón’s internal reserve engineers and pro forma to exclude non-core assets in East Texas and Eastern Montana sold in 2Q14.
4
Consistent Production Growth Pro Forma Production Growth (MBoe/d) (1) ~140% Increase in Daily Production
Actual PF Production Guidance Midpoint
33.5
32.8
PF 4Q13
PF 1Q14
28.0 17.5
PF 1Q13
40.4
42.0
PF 2Q14
3Q14 Guidance
19.6
PF 2Q13
PF 3Q13
5 (1) Pro forma to include all acquisition and divestiture activity to date.
Significant Per Unit Cost Improvements Historical $ LOE (1)/Boe & $ G&A/Boe (2) $12.22
$11.97
$10.79 $9.13
2Q13
Q/Q
Y/Y
$5.86
$7.56
$5.86
2Q14
1Q14 $ LOE / Boe
Q/Q
$ LOE / Boe:
(25%)
(24%)
$ G&A / Boe:
(46%)
(22%)
(2) G&A is recurring cash G&A (excluding non-cash compensation expense).
2Q14
$ G&A / Boe
Y/Y
(1) Includes workover expense.
$9.13
6
Geologic Setting Eagle Ford Shale
HK Lease Area Play Outline
- 100-300’ organic rich shale target - 6,500-10,500’ depth range - 7-10% GRI measured porosity - 2-4% TOC by weight - Pressure gradient: 0.55-0.65 psi/ft 7 Source: Bureau of Economic Geology.
Eagle Ford Shale Highlights • • • • • • •
Discovered in October 2008 in LaSalle County by Petrohawk and FRI ~11,700 wells have produced in 26 counties Cumulative Production (as of June 2014): 630 MMBO, 220 MMBC, and 3.7 TCF Current Production (2014 avg): 1 MMBO/day, 233 MMBC/day, and 4 BCF/day ~260 rigs currently drilling ~3,900 drilling permits currently filed Contributed billions of dollars to the Texas economy
8 Source: Railroad Commission of Texas Production Data Query System.
Eagle Ford Shale at Night
9
Source: EagleFordShaleBlog.com
Eagle Ford Shale / TMS Stratigraphic Cross Section Eagle Ford Shale / Tuscaloosa Marine Shale West to East Stratigraphic Cross Section A – A’ Dimmit Co., Texas to Wilkinson Co., Mississippi
DATUM: AUSTIN CHALK S TX EAGLE FORD SHALE
WOODBINE SANDS
SAN MARCOS ARCH
BUDA
E TEXA S BASI N SAN MAR COS ARCH
SABI NE UPLIF T
EL HALCON EAGLE FORD
SABINE UPLIFT
UPPER TUSCALOOSA SANDS
TUSCALOOSA MARINE SHALE TMS Play
EAST TEXAS BASIN LOWER TUSCALOOSA SANDS
10
Eagle Ford Shale / Woodbine / TMS Cross Section
11
Comparison of South Texas and East Texas Eagle Ford South Texas Eagle Ford
East Texas Eagle Ford
TOC > 2% by weight
TOC > 2% by weight
Ave. Resistivity > 10 ohms
Ave. Resistivity 4 to 10 ohms
Ave. Clay content < 20% Low swelling clay
San Marcos Arch
Ave. Clay content 25% to 45% Low swelling clay
100’ to 300’ thick
100’ to 200’ thick
Good frac barriers below
Good frac barriers above and below
Long transition from oil to gas
Short transition from oil to gas
12
El Halcón Eagle Ford Shale – Again… Highlights ~101,000 net acres leased – target achieved ̶ Acreage in “SWEET SPOT” of play ̶ 800 - 1,000+ future locations to drill depending on spacing assumptions
2H14 Outlook ̶ Expect to spud ~22 gross operated wells with 3 rigs
Improving Well Economics ̶ Reduced drilling days and lower frac cost ̶ Improvement in D&C techniques ongoing ̶ Optimizing artificial lift
Acreage De-risked ̶ Entire position de-risked through operated step outs and offset results by other operators 13
Tremendous Success To-Date in El Halcón Additional Upside Potential to Unlock
HK Operated Spuds Other Operator Spuds
150
2 Improve drilling efficiencies 100
50
Source: IHS
1Q13
2Q13
3Q13
…ongoing improvements will continue to unlock value in 2015+ 1 Shift from delineation into lease capture Peer and operated wells have de-risked entire position Approximately 60% of acreage already HBP
4Q13
1Q14
2Q14
0
Well Count
Total El Halcón Spud Count
Activity has quickly accelerated since HK’s entry into El Halcón in 2013…
Optimize two vs. three string design by area Continue to reduce drill days Area specific experience reducing non-productive time
3 Optimize completion design
Currently testing stage length, cluster spacing, proppant mix, fluid chemistry, artificial lift modifications, etc. Expected to lead to increased recoveries
4 Determine optimal spacing across acreage position HK testing 1,000’ and 800’ spacing Other operators testing 500’ spacing
5 Potential prospectivity for other zones Austin Chalk / Buda Woodbine 14
Entire El Halcón Acreage Position De-Risked
Halcón – Reveille 1H IP: 1,416 Boe/d Halcón – Keystone 1H IP: 975 Boe/d Halcón – J.B. Ranch 1H IP: 1,203 Boe/d
Halcón – Wilco 1H IP: 978 Boe/d Halcón – Stifflemire 1H IP: 1,066 Boe/d
CWEI – Pivonka E Unit 1H IP: 1,266 Boe/d
Sabalo Exploration – Koontz Heirs 1H IP: 939 Boe/d Halcón – Javelina 1H IP: 1,171 Boe/d Halcón – Wombat 2H IP: 839 Boe/d Halcón – Oystercatcher 1H IP: 839 Boe/d Apache – McCullough-Wineman EF 2H IP: 1,900 Boe/d Halcón – Stasny Honza 1H IP: 1,262 Boe/d
Halcón – Snapper 1H IP: 866 Boe/d Halcón – Snapper 2H IP: 931 Boe/d
Halcón Acreage Outline
Halcón Operator Drilling Offset Operator Drilling Recent Permits
Halcón EF Wells Halcón Waiting on Completion Offset EF Wells Apache EF Wells Offset Waiting on Completion / Flowback Clayton Williams EF Wells Anadarko EF Wells
PMO – Snoe 1H IP: 1,080 Boe/d Comstock – Henry A 1H IP: 1,299 Boe/d 15
El Halcón (East TX Eagle Ford Shale) Isopach HK Acreage Located in “SWEET SPOT” of Play
16
El Halcón Cross Section Offset to HK Reveille 1H
IP: 1,066 Boe/d
IP: 1,203 Boe/d
HK Reveille 1H IP: 1,416 Boe/d
IP: 1,054 Boe/d
17
Eagle Ford Shale Log and Core Halcón Resources Red Stag
Dark grey to black organic rich shale
Brazos County, Texas
Austin Chalk
Mechanical Frac barrier
XRD Mineralogy by % volume
Upper Reservoir
Lower Reservoir
Reservoir Mechanical barrier Buda Limestone
18
Eastern Eagle Ford and TMS Lithology
% Volume
Clay Distribution •
•
Total clay content is high, but % of swelling clays (smectite) is low being only 1-5% Total clay and smectite % in TMS is very similar to Eagle Ford Shale at El Halcón
19
2D SEM (A Look At Organic Porosity)
20
Austin Chalk Production
21
Eastern Eagle Ford Seismic •
•
Twelve 3D surveys encompassing 3,218 squares miles have been shot or are in progress All of Halcón’s acreage soon to be covered by 3D surveys
22
Brazos County 2D Line N
Grouper 1H
S
Eagle Ford Top Chalk
Buda
Seismic data owned or controlled by Seismic Exchange, Inc.; interpretation is that of Halcón Resources.
12 miles
23
Cumulative Production, Boe
El Halcón Representative Wells
Producing Days 24 Note: Downtime excluded, no prior drainage, >1,000’ spacing, >1,200 lbs prop/ft, >4,000’ completed lateral length, mechanically compromised wellbores excluded.
Significant Reduction in CWC Expected with Development Phase El Halcón Lease Capture vs. Development Plan Cost Savings Completed Well Cost ($ in 000’s)
Current ($350)
Land/Title
($300) ($300) ($250)
• Initial pooled unit wells incur the majority of expense for title verification
Location
Savings of ~$1.2 MM
• Utilization of existing roads and pads should dramatically reduce development well cost
Drilling Operations • Reduction in days due to efficiency gains and optimization of design and setup
Facilities & Hookup • Development wells will utilize existing facilities and pipelines
New Best-In-Class Well Alacran 1H Spud-TD: 11.58 days Speed: 1,393 feet/day Lateral Length: ~7,000’
25
El Halcón 452 MBoe Type Curve EUR Increases by ~22% Investment Sensitivity to Completed Well Cost (1) $5.0
40%
$4.0
30%
$3.0
20%
$2.0
10%
$1.0
0%
$0.0 $8.0
$8.5
$9.0
$9.5
Gross EUR
IRR %
PV-10
Diffs (3)
IRR
50%
Type Curve Details
$6.0
PV-10 ($ MM)
60%
$10.0
Oil (MBbl)
420
Gas (MMcf)
189
Total (MBoe)
452
Oil (% of NYMEX)
99%
Gas (% of NYMEX)
180%
IP (Boe/d)
CWC ($ MM)
770
Spud to Production
Investment Sensitivity to NYMEX Oil Price (2) $8.0
60%
$6.0
40%
$4.0
20%
$2.0
0%
$0.0 $80
$90
$100
$110
B factor
Other
IRR %
80%
PV-10
PV-10 ($ MM)
IRR
60 days 1.3
Di
81%
Df
6%
Lateral Length (ft)
7,500
Avg. Royalty Burden
~25%
Avg. Working Interest
~70%
Avg. Net Revenue Interest
$/Bbl – NYMEX oil Note: See “Cautionary Statements” on page 3 for a description of EURs. (1) Assumes flat pricing of $95/bbl oil and $4.50/MMBtu gas. (2) Assumes $9 MM CWC & $4.50/MMBtu gas. (3) Gathering, transportation and processing fees incorporated; Gas differentials presented on a gross wellhead basis including differential uplift for high BTU/NGL content.
~53%
(1) 26
Conclusions • • • • •
Eagle Ford Shale established as one of the largest oil and gas fields in the world East Texas Eagle Ford and TMS are the exact same time equivalent reservoir East Texas Eagle Ford (El Halcón) is a new Eagle Ford core area Drilling, production, and seismic acquisitions in El Halcón are very significant Economics of El Halcón are very compelling
27
Contact: Charles Cusack III, EVP & COO 1000 Louisiana St., Suite 6700 Houston, TX 77002 832-538-0566 [email protected]
www.halconresources.com
Forward-Looking Statements
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 using words such as "expects", "anticipates", "plans", "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 resources involved can be economically exploited. Forward-looking statements are subject to risks and uncertainties, which could cause actual results to differ materially from those reflected in the statements. These risks include, but are not limited to: operational risks in exploring for, developing and producing crude oil and natural gas; uncertainties involving geology of oil and natural gas deposits; the timing of and potential proceeds from planned divestitures; uncertainty of reserve estimates; uncertainty of estimates and projections relating to future production, costs and expenses; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; health, safety and environmental risks and risks related to weather such as hurricanes and other natural disasters; uncertainties as to the availability and cost of financing; fluctuations in oil and natural gas prices; risks associated with derivative positions; inability to realize expected value from acquisitions, inability of our management team to execute 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' pro forma 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 the projections in the 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 estimates or opinions change. 2
Cautionary Statements
The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible— from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves, however, we currently do not disclose probable or possible reserves in our SEC filings. 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. “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 all of the drilling locations which have been attributed these quantities. 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 may be affected by significant commodity price declines or drilling cost increases. 3
Company Profile Significant Resource Opportunity Total Proved Reserves: (1)
Bakken/Three Forks ~131,000 Net Acres
119.6 MMBoe
% Proved Developed:
41%
% Oil:
84%
% Operated:
92%
90.4 MMBoe Proved Reserves (1)
Other 6.5 MMBoe Proved Reserves (1)
Total Proved PV10: (1)
$2,317 MM
Net Unrisked Resource Potential: (2) 2Q14 PF Net Daily Prod: (1)
~1.3 BBoe 40,396 Boe/d
El Halcón ~101,000 Net Acres 22.7 MMBoe Proved Reserves (1)
TMS ~316,000 Net Acres
Note: See “Cautionary Statement Regarding Hydrocarbon Quantities” on page 3 for a description of resource potential.
(1)
(2)
Proved reserves and PV10 as of 12.31.13 as estimated by Halcón’s independent reserve engineers using unweighted average first-day-of-the-month commodity prices for the year ended 12.31.13 and in accordance with SEC rules relating to reporting of reserves; Proved reserves, PV10 , 2Q14 and current production pro forma to exclude non-core assets in East Texas and Eastern Montana sold in 2Q14. Net unrisked resource potential calculated by Halcón’s internal reserve engineers and pro forma to exclude non-core assets in East Texas and Eastern Montana sold in 2Q14.
4
Consistent Production Growth Pro Forma Production Growth (MBoe/d) (1) ~140% Increase in Daily Production
Actual PF Production Guidance Midpoint
33.5
32.8
PF 4Q13
PF 1Q14
28.0 17.5
PF 1Q13
40.4
42.0
PF 2Q14
3Q14 Guidance
19.6
PF 2Q13
PF 3Q13
5 (1) Pro forma to include all acquisition and divestiture activity to date.
Significant Per Unit Cost Improvements Historical $ LOE (1)/Boe & $ G&A/Boe (2) $12.22
$11.97
$10.79 $9.13
2Q13
Q/Q
Y/Y
$5.86
$7.56
$5.86
2Q14
1Q14 $ LOE / Boe
Q/Q
$ LOE / Boe:
(25%)
(24%)
$ G&A / Boe:
(46%)
(22%)
(2) G&A is recurring cash G&A (excluding non-cash compensation expense).
2Q14
$ G&A / Boe
Y/Y
(1) Includes workover expense.
$9.13
6
Geologic Setting Eagle Ford Shale
HK Lease Area Play Outline
- 100-300’ organic rich shale target - 6,500-10,500’ depth range - 7-10% GRI measured porosity - 2-4% TOC by weight - Pressure gradient: 0.55-0.65 psi/ft 7 Source: Bureau of Economic Geology.
Eagle Ford Shale Highlights • • • • • • •
Discovered in October 2008 in LaSalle County by Petrohawk and FRI ~11,700 wells have produced in 26 counties Cumulative Production (as of June 2014): 630 MMBO, 220 MMBC, and 3.7 TCF Current Production (2014 avg): 1 MMBO/day, 233 MMBC/day, and 4 BCF/day ~260 rigs currently drilling ~3,900 drilling permits currently filed Contributed billions of dollars to the Texas economy
8 Source: Railroad Commission of Texas Production Data Query System.
Eagle Ford Shale at Night
9
Source: EagleFordShaleBlog.com
Eagle Ford Shale / TMS Stratigraphic Cross Section Eagle Ford Shale / Tuscaloosa Marine Shale West to East Stratigraphic Cross Section A – A’ Dimmit Co., Texas to Wilkinson Co., Mississippi
DATUM: AUSTIN CHALK S TX EAGLE FORD SHALE
WOODBINE SANDS
SAN MARCOS ARCH
BUDA
E TEXA S BASI N SAN MAR COS ARCH
SABI NE UPLIF T
EL HALCON EAGLE FORD
SABINE UPLIFT
UPPER TUSCALOOSA SANDS
TUSCALOOSA MARINE SHALE TMS Play
EAST TEXAS BASIN LOWER TUSCALOOSA SANDS
10
Eagle Ford Shale / Woodbine / TMS Cross Section
11
Comparison of South Texas and East Texas Eagle Ford South Texas Eagle Ford
East Texas Eagle Ford
TOC > 2% by weight
TOC > 2% by weight
Ave. Resistivity > 10 ohms
Ave. Resistivity 4 to 10 ohms
Ave. Clay content < 20% Low swelling clay
San Marcos Arch
Ave. Clay content 25% to 45% Low swelling clay
100’ to 300’ thick
100’ to 200’ thick
Good frac barriers below
Good frac barriers above and below
Long transition from oil to gas
Short transition from oil to gas
12
El Halcón Eagle Ford Shale – Again… Highlights ~101,000 net acres leased – target achieved ̶ Acreage in “SWEET SPOT” of play ̶ 800 - 1,000+ future locations to drill depending on spacing assumptions
2H14 Outlook ̶ Expect to spud ~22 gross operated wells with 3 rigs
Improving Well Economics ̶ Reduced drilling days and lower frac cost ̶ Improvement in D&C techniques ongoing ̶ Optimizing artificial lift
Acreage De-risked ̶ Entire position de-risked through operated step outs and offset results by other operators 13
Tremendous Success To-Date in El Halcón Additional Upside Potential to Unlock
HK Operated Spuds Other Operator Spuds
150
2 Improve drilling efficiencies 100
50
Source: IHS
1Q13
2Q13
3Q13
…ongoing improvements will continue to unlock value in 2015+ 1 Shift from delineation into lease capture Peer and operated wells have de-risked entire position Approximately 60% of acreage already HBP
4Q13
1Q14
2Q14
0
Well Count
Total El Halcón Spud Count
Activity has quickly accelerated since HK’s entry into El Halcón in 2013…
Optimize two vs. three string design by area Continue to reduce drill days Area specific experience reducing non-productive time
3 Optimize completion design
Currently testing stage length, cluster spacing, proppant mix, fluid chemistry, artificial lift modifications, etc. Expected to lead to increased recoveries
4 Determine optimal spacing across acreage position HK testing 1,000’ and 800’ spacing Other operators testing 500’ spacing
5 Potential prospectivity for other zones Austin Chalk / Buda Woodbine 14
Entire El Halcón Acreage Position De-Risked
Halcón – Reveille 1H IP: 1,416 Boe/d Halcón – Keystone 1H IP: 975 Boe/d Halcón – J.B. Ranch 1H IP: 1,203 Boe/d
Halcón – Wilco 1H IP: 978 Boe/d Halcón – Stifflemire 1H IP: 1,066 Boe/d
CWEI – Pivonka E Unit 1H IP: 1,266 Boe/d
Sabalo Exploration – Koontz Heirs 1H IP: 939 Boe/d Halcón – Javelina 1H IP: 1,171 Boe/d Halcón – Wombat 2H IP: 839 Boe/d Halcón – Oystercatcher 1H IP: 839 Boe/d Apache – McCullough-Wineman EF 2H IP: 1,900 Boe/d Halcón – Stasny Honza 1H IP: 1,262 Boe/d
Halcón – Snapper 1H IP: 866 Boe/d Halcón – Snapper 2H IP: 931 Boe/d
Halcón Acreage Outline
Halcón Operator Drilling Offset Operator Drilling Recent Permits
Halcón EF Wells Halcón Waiting on Completion Offset EF Wells Apache EF Wells Offset Waiting on Completion / Flowback Clayton Williams EF Wells Anadarko EF Wells
PMO – Snoe 1H IP: 1,080 Boe/d Comstock – Henry A 1H IP: 1,299 Boe/d 15
El Halcón (East TX Eagle Ford Shale) Isopach HK Acreage Located in “SWEET SPOT” of Play
16
El Halcón Cross Section Offset to HK Reveille 1H
IP: 1,066 Boe/d
IP: 1,203 Boe/d
HK Reveille 1H IP: 1,416 Boe/d
IP: 1,054 Boe/d
17
Eagle Ford Shale Log and Core Halcón Resources Red Stag
Dark grey to black organic rich shale
Brazos County, Texas
Austin Chalk
Mechanical Frac barrier
XRD Mineralogy by % volume
Upper Reservoir
Lower Reservoir
Reservoir Mechanical barrier Buda Limestone
18
Eastern Eagle Ford and TMS Lithology
% Volume
Clay Distribution •
•
Total clay content is high, but % of swelling clays (smectite) is low being only 1-5% Total clay and smectite % in TMS is very similar to Eagle Ford Shale at El Halcón
19
2D SEM (A Look At Organic Porosity)
20
Austin Chalk Production
21
Eastern Eagle Ford Seismic •
•
Twelve 3D surveys encompassing 3,218 squares miles have been shot or are in progress All of Halcón’s acreage soon to be covered by 3D surveys
22
Brazos County 2D Line N
Grouper 1H
S
Eagle Ford Top Chalk
Buda
Seismic data owned or controlled by Seismic Exchange, Inc.; interpretation is that of Halcón Resources.
12 miles
23
Cumulative Production, Boe
El Halcón Representative Wells
Producing Days 24 Note: Downtime excluded, no prior drainage, >1,000’ spacing, >1,200 lbs prop/ft, >4,000’ completed lateral length, mechanically compromised wellbores excluded.
Significant Reduction in CWC Expected with Development Phase El Halcón Lease Capture vs. Development Plan Cost Savings Completed Well Cost ($ in 000’s)
Current ($350)
Land/Title
($300) ($300) ($250)
• Initial pooled unit wells incur the majority of expense for title verification
Location
Savings of ~$1.2 MM
• Utilization of existing roads and pads should dramatically reduce development well cost
Drilling Operations • Reduction in days due to efficiency gains and optimization of design and setup
Facilities & Hookup • Development wells will utilize existing facilities and pipelines
New Best-In-Class Well Alacran 1H Spud-TD: 11.58 days Speed: 1,393 feet/day Lateral Length: ~7,000’
25
El Halcón 452 MBoe Type Curve EUR Increases by ~22% Investment Sensitivity to Completed Well Cost (1) $5.0
40%
$4.0
30%
$3.0
20%
$2.0
10%
$1.0
0%
$0.0 $8.0
$8.5
$9.0
$9.5
Gross EUR
IRR %
PV-10
Diffs (3)
IRR
50%
Type Curve Details
$6.0
PV-10 ($ MM)
60%
$10.0
Oil (MBbl)
420
Gas (MMcf)
189
Total (MBoe)
452
Oil (% of NYMEX)
99%
Gas (% of NYMEX)
180%
IP (Boe/d)
CWC ($ MM)
770
Spud to Production
Investment Sensitivity to NYMEX Oil Price (2) $8.0
60%
$6.0
40%
$4.0
20%
$2.0
0%
$0.0 $80
$90
$100
$110
B factor
Other
IRR %
80%
PV-10
PV-10 ($ MM)
IRR
60 days 1.3
Di
81%
Df
6%
Lateral Length (ft)
7,500
Avg. Royalty Burden
~25%
Avg. Working Interest
~70%
Avg. Net Revenue Interest
$/Bbl – NYMEX oil Note: See “Cautionary Statements” on page 3 for a description of EURs. (1) Assumes flat pricing of $95/bbl oil and $4.50/MMBtu gas. (2) Assumes $9 MM CWC & $4.50/MMBtu gas. (3) Gathering, transportation and processing fees incorporated; Gas differentials presented on a gross wellhead basis including differential uplift for high BTU/NGL content.
~53%
(1) 26
Conclusions • • • • •
Eagle Ford Shale established as one of the largest oil and gas fields in the world East Texas Eagle Ford and TMS are the exact same time equivalent reservoir East Texas Eagle Ford (El Halcón) is a new Eagle Ford core area Drilling, production, and seismic acquisitions in El Halcón are very significant Economics of El Halcón are very compelling
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Contact: Charles Cusack III, EVP & COO 1000 Louisiana St., Suite 6700 Houston, TX 77002 832-538-0566 [email protected]
www.halconresources.com
