bank of america merrill lynch conference · core upstream producing areas 5 gas 54% 29% ngls q1...
TRANSCRIPT
Bank of America Merrill LynchEnergy Credit Conference
June 7, 2017
Forward Looking Statement
2
This presentation contains forward‐looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward‐looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward‐looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward‐looking. Without limiting the generality of the foregoing, forward‐looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward‐looking statements. These include risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company’s business plan, the Company’s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results to differ materially from those projected. Any forward‐looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward‐looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In this communication, the Company uses the term “unproved reserves” which the SEC guidelines prohibit from being included in filings with the SEC. “Unproved reserves” refers to the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. Unproved reserves may not constitute reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or proposed SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company’s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company’s ongoing drilling program, which will be directly affected by 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 actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company’s core assets provide additional data. 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.
This presentation contains financial measures that have not been prepared in accordance with U.S. Generally Accepted Accounting Principles (“non‐GAAP financial measures”) including LTM EBITDA and certain debt ratios. The non‐GAAP financial measures should not be considered a substitute for financial measures prepared in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). We urge you to review the reconciliations of the non‐GAAP financial measures to GAAP financial measures in the appendix.
Unit Corporation: A Diversified Energy Company
3
12
10
5
54
13
Casper Casper
Houston Houston
Oklahoma City
Oklahoma City
PittsburghPittsburgh
Tulsa HeadquartersTulsa HeadquartersArkoma Basin
Marcellus
North La/ East Texas Basin
Gulf Coast Basin
Anadarko Basin
Permian Basin94 Unit Rigs
E&P Operations
Mid‐Stream Operations
Office Location
• Tulsa based, incorporated in 1963
• Integrated approach to business allows Unit to capture margin from each business segment
Company Highlights
4
• Highly economic opportunities for our E&P segment
• Contract drilling segment growing with industry rebound
• Midstream segment EBITDA poised for growth
• Fiscally conservative• Capital spending within cash flow
Core Upstream Producing Areas
5
Gas54%
29%NGLs
Q1 2017 Daily Production: 42.0 MBoe/d
Key focus areas include:Gulf Coast: Wilcox (Southeast Texas)
Mid‐Continent: Hoxbar (Western Oklahoma) Granite Wash (Texas Panhandle)
Mid Continent Region
Upper Gulf Coast Region
Wilcox
HoxbarGranite Wash
0102030405060
2013 2014 2015 2016 2017 estNatural Gas Oil / NGLs
91 121 10
Average Production (MBoe/d)
44‐4646 4750 55
35Net Wells Drilled:
17%Oil
2016 year end total proves reserves: 707 Bcfe or 118 MMBoe
~25
Buffalo Wallow Field – Economic Advantages
6
Geology‐11 Granite Wash lenses‐Sands consistent across field
Land‐~8,800 net acres ‐Operated and ~90% HBP‐Average working interest ~ 90%‐220 ‐ 270 potential XL locations ‐Resumed drilling in December 2016‐Continue to expand position
Infrastructure‐SWD network lowers disposal costs ‐80% and allows for water recycling‐Electricity throughout field‐Superior Pipeline gathers and processes the gas
Buffalo Wallow Extended Lateral Results
7
5 BCFE *UPC ROR: 9% Corp ROR: 16%
8 BCFE * UPC ROR: 36%Corp ROR: 58%
11 BCFE *UPC ROR: 82%Corp ROR: 130%
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
0 20 40 60 80 100 120 140 160 180 200
Cumulative Prod
uctio
n (M
MCFE)
Days1 5/25/2017 Strip Price Deck with 1st Production Starting 1/1/2017;See Q2 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html).
2 ROR calculation includes midstream margin.
(1)
(1)
(1)
(1) (2)
(1) (2)
(1) (2)
ROR assumes well cost of $6.3MM
1st C1
2nd C1
1st A2
* Potential EUR Range
Hoxbar (Marchand Sand)
8
H O X B A R 3 , 0 0 0 ’
Hoxbar Marchand Core Area‐EUR ~ 550 MBoe‐Estimated well cost $5.0 MM‐83% liquids (68% oil)‐~26,000 net acres (64% HBP)‐60‐65 locations‐Working interest of 50‐60%‐ROR1 ~ 100%‐Resumed drilling in late April ‐5‐6 wells for remainder 2017
Future Growth‐Extended laterals (XL’s)‐Performing waterflood study ‐Waterflood offers significant upside potential
1 5/25/2017 Strip Price Deck with 1st Production Starting 6/1/2017;See Q2 2017 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
‐Paid $56.75MM cash plus contributed 180 acres in McClain County
‐47 PDP wells23 operated by seller20 operated by Unit
‐Proved reserves = 3.2 MMBoe
‐Production = 1,367 boepd (73% liquids)
‐65 gross potential Hoxbar locations13 new locations52 planned wells with working interest increased to ≥80%
‐8,335 net acres (71% HBP)42% increase over existing acreageNow 26,000 net acres in playExcellent overlap with existing acreage
‐Planned secondary recovery projects will substantially increase oil recoveries
Hoxbar Acquisition
9
Unit
Acquired
Add’l Interest Acquired
Wilcox (Southeast Texas)
10
Overall Wilcox Highlights ‐Drilled 164 operated wells since 2003(155 vertical, 9 horizontal)‐Program ROR > 100%‐Operated with working interest ~ 92%‐Production: ~ 90 MMcfe/d (42% liquids)‐Resumed drilling activity in Jan. 2017JASPER
POLK
3D AREA494 mi.²
HARDIN
Prior Years DrillingHorizontal Wells
TYLER
Gilly Field
0
10
20
30
40
2012 2013 2014 2015 2016
Gas Oil NGLs
Wilcox Annual ProductionBcfe
Gilly Field – World Class Gas Reservoir‐500 Bcfe stacked pay gas resource‐Cumulative production ~ 100 Bcfe‐Average EUR of 10‐20 Bcfe per well‐Typical well cost ~ $6 MM‐ROR > 100%
Future Growth‐Over 100 stacked pay recompletions and workovers to do in existing wells‐Latest horizontal IP 30: 9 MMcf/d, 240 Bopd‐First of 2 exploratory wells waiting on frack‐Generating new exploration ideas using 165 square miles of 3‐D data
Wilcox Activity Map for 2017
11
POLK
HARDIN
TYLER
LIBERTY
CHERRY CREEK
GILLY VILLAGE MILLS
SEGNO NE
WING
2016 Wilcox Recompletions& Workover Results
12
Composite Gross Production from Recompletions and Workovers20 Recompletions & 7 Workovers Total Cost: $10MM
Start of Year3,360 mcfd80 bopd
End of Year40,000 mcfd1,100 bopd
Wilcox Horizontal Test –Village Mills Field
13
Depth Map on Dempsey Sd
0.23 BCFG2.3 MMCF/D IP48,000# Frac
1.03 BCFG2.6 MMCF/D IP214,000# Frac
1.45 BCFG1.8 MMCF/D IP72,000# Frac
West Univ. #1H5,800’ LateralIP30: 9 MMCF/D, 240 BO/D3,000# Flowing Pressure22 Stage, 5,300,000# Frac
Rig Fleet Presence in Key Regions
14
10
12
54
135
Area # of RigsMid‐Continent 17
Bakken 3Niobrara 1Permian 6Pinedale 2Total 29
Current Rigs Operating(1)
94 rig fleet
69% electric 56% 1,500 HP or greater 94 equipped with top drives 59 equipped with skidding or walking systems
31% total fleet utilization at present Nine BOSS rigs operating
20 ≤800 HP: 21%70 1,000‐1,700 HP: 75%4 ≥2,000 HP: 4%
(1) As of June 5, 2017.
SCR Rigs Continue to Make anImportant Contribution
15
0
5
10
15
20
25
30
May 5, 2016 Aug. 4, 2016 Dec. 31, 2016 Jun. 5, 2017
A/C SCR
• At industry trough – 13 drilling rigs operating
• Currently, 29 drilling rigs operating
• Four additional SCR rigs under contract
• All BOSS rigs operating
• 20 SCR rigs operating̶ 13 SCR rigs required
no modifications̶ 7 SCR rigs required
some upgrade
7
9
12
20
6 79 9
Average Dayrates and Margins (1)
16
Average Rig Utilization
Margins and
Dayrates
$0
$5,000
$10,000
$15,000
$20,000
2008 2009 2010 2011 2012 2013 2014 2015 2016 Q1 '17
Margins Dayrates Average Rig Utilization
100%
75%
50%
25%
0%
(1) See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix(also available at www.unitcorp.com/investor/reports.html).
The BOSS Drilling Rig
17
Optimized for Pad Drilling Multi‐direction walking system
Faster Between Locations Quick assembly substructure 32‐34 truck loads
More Hydraulic Horsepower (2) 2,200 horsepower
mud pumps 1,500 gpm available
with one pump
Environmentally Conscious Dual‐fuel capable
engines Compact location
footprint
All nine BOSS rigs currently operating; tenth under construction
Midstream Core Operations
18
Appalachia 66,000+ dedicated acres 53 miles of gathering pipeline Connected 24 new wells in2016
TulsaHeadquarters
PittsburghRegional office
Hemphill
Reno
Bellmon
Segno
Pittsburgh Mills
Processing facilities
Gathering systems
Panola
Key Metrics
• 25 active systems
• Three natural gas treatment plants
• 340 MMcf/d processing capacity
• Q1’17 processing volume 127 MMcf/d
• Approx. 1,470 miles of pipeline
East Texas 66 Miles of gathering pipeline 120 MMcf/d gathering capacity
Texas Panhandle 52,000 dedicated acres 135 MMcf/d processing capacity 343 miles of gathering pipeline
Northern Oklahoma and Kansas 1,975,000+ dedicated acres 193 MMcf/d processing capacity 579 miles of gathering pipeline
Central & Eastern OK 57,000+ dedicated acres 12 MMcf/d processing capacity 428 miles of gathering pipeline
Brook Field
Snow Shoe
Bruceton Mills
Midstream Segment Contract Mix
19
Contract Mix Based on Margin
Fee BasedCommodity Based
85%35%
65%
15%
Contract Mix Based on Volume
Fee BasedCommodity Based
49%28%
72%51%
2010 Q1 2017
Unit vs. 3rd Party Margin Contribution
3rd PartyUnit
41% 35%65%59%
Midstream Historical Volumes
20
‐
20,000,000
40,000,000
60,000,000
80,000,000
100,000,000
120,000,000
140,000,000
160,000,000
180,000,000
200,000,000
2009 2010 2011 2012 2013 2014 2015 2016
Gas Gathered (MMbtu) Gas Processed (MMbtu)
MMBtu
Gathe
red & Processed
Midstream SegmentCommodity Price Sensitivity (1)
21
$0
$10,000,000
$20,000,000
$30,000,000
$40,000,000
$50,000,000
$60,000,000
$70,000,000
2009 2010 2011 2012 2013 2014 2015 2016 2016Adjusted
$29.40 $38.64 $43.26 $31.50 $35.70 $30.24 $15.96 $15.96 $21.07$54.89 $75.07 $88.47 $89.93 $87.46 $81.25 $37.03 $32.56 $47.33
Realized Price*NGL/Barrel:
Condensate/Bbl:
*Net realized prices – prices received after transportation, fuel, and fees paid.(1) See Superior Pipeline Company Reconciliation of EBITDA in Appendix (also available at www.unitcorp.com/investor/reports.html).
Segment EBITDA Before Intercompany Eliminations
2016 Adjustments
• Utilized 2016 volumes
• Assumed $55.00/Bbl oil price
• Adjusted for average NGL price of $21.07/Bbl
• Adjusted average condensate price of $47.33/Bbl
• Prices are after transportation, fuel, and fees paid.Adjusted
PriceRealized Price
* Drilling rigs are not included in borrowing base.
Debt Structure – No Near‐Term Maturities
22
Senior Subordinated Notes
$650 million, 6.625%
10‐year, NC5; maturity 2021
Key Covenants Interest coverage ratio ≥ 2.25x(1)
Secured Bank Facility (Redetermined April 2017) * Elected Commitment
and Current Borrowing Base $475 million
Outstanding(2) $150.0 million
Maturity April 2020
Key Covenants Current ratio ≥ 1.0 to 1.0(1)
Senior Indebtedness ratio ≤ 2.75(1)
(1) As defined in Indenture/Credit Agreement.(2) As of March 31, 2017.
Ratings S&P Moody’s FitchCorporate B+ B2 B+Senior Subordinated Notes BB‐ B3 BB‐
3/31/20175.07x(1,2)
3/31/2017 Actual3.10x(1,2)
0.54x(1,2)
Segment Contribution
23
Oil and Natural Gas Contract Drilling Midstream
Revenues ($ millions) Adjusted EBITDA ($ millions)(1)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2013 2014 2015 2016 Q1 '17
$0
$200
$400
$600
$800
2013 2014 2015 2016 Q1 '17
$1,352
$1,573
$854
$602
$176
$787
$410
$252
$75
$667
(1) See Non‐GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html).
Operating Segment Capital Expenditures
24
$0
$500
$1,000
$1,500
2013 2014 2015 2016 2017 Budget
Oil and Natural Gas Contract Drilling Midstream
(In Millions)
Investment Considerations
25
• E&P segment three core areas provide compelling economics
• Contract drilling segment resuming pattern of growth
• Midstream segment positioned to benefit from increased activity levels and liquids price improvement
• We maintain fiscal discipline• Solid balance sheet with ample liquidity
26
APPENDIX
Non‐GAAP Financial Measures ‐ Corporate
27
Adjusted EBITDAYears endedDecember 31,
($ In Millions) 2017 2013 2014 2015 2016
Net Income (Loss) ($41) $16 $185 $136 ($1,037) ($136)Income Taxes (16) 14 117 87 (627) (71)Depreciation, Depletion and Amortization 56 47 334 405 355 210
Impairments 38 ‐ ‐ 158 1,635 162 Interest Expense 10 9 15 17 32 40 (Gain) loss on derivatives (11) (15) 8 (30) (26) 23Settlements during the period of matured derivative contracts 7 (1) (2) (6) 47 10
Stock compensation plans 5 4 22 24 21 14 Other non‐cash items 1 1 5 5 3 3 (Gain) loss on disposition of assets (1) ‐ (17) (9) 7 (3) Adjusted EBITDA $48 $75 $667 $787 $410 $252
2016
Three months endedMarch 31,
Non‐GAAP Financial Measures ‐ Segments
28
Unit PetroleumIncome (Loss) Before Income Taxes (1) $ (45) $ 36 $ 239 $ 199 $ (1,631) $ (102)
Depreciation, Depletion and Amortization 32 22 226 276 252 114Impairment of Oil and Natural Gas Properties 38 ‐ ‐ 77 1,599 162
Adjusted EBITDA $ 25 $ 58 $ 465 $ 552 $ 220 $ 174
Unit DrillingIncome (Loss) Before Income Taxes (1) $ (1) $ (5) $ 96 $ 42 $ 45 $ (13)
Depreciation and Impairment 12 13 71 160 64 47Adjusted EBITDA $ 11 $ 8 $ 167 $ 202 $ 109 $ 34
Superior PipelineIncome (Loss) Before Income Taxes (1) $ (3) $ 2 $ 11 $ 2 $ (30) $ 2
Depreciation, Amortization and Impairment 11 11 33 48 71 46Adjusted EBITDA $ 8 $ 13 $ 44 $ 50 $ 41 $ 48
(1) After intercompany eliminations and does not include allocation of G&A expense.
Adjusted EBITDA
($ In Millions) 2017 2013 2014 2015 20162016
Years endedDecember 31,
Three months endedMarch 31,
Non‐GAAP Financial Measures
29
Reconciliation of Average Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense
(In thousands except for operating daysand operating margins) 2016 2013 2014 2015 2016
Contract drilling revenue $38,710 $37,185 $414,778 $476,517 $265,668 $122,086
Contract drilling operating cost 28,098 29,227 247,280 274,933 156,408 88,154
Operating profit from contract drilling $10,612 $7,958 $167,498 $201,584 $109,260 $33,932
Add:
Elimination of intercompany rig profit and bad debt expense ‐ ‐ 17,416 29,343 3,991 235
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense
10,612 7,958 184,914 230,927 113,251 34,167
Contract drilling operating days 1,878 2,291 23,720 27,516 12,681 6,374
Average daily operating margin beforeelimination of intercompany rig profit and bad debt expense
$5,651 $3,474 $7,796 $8,392 $8,931 $5,360
2017
Years endedDecember 31,
Three months endedMarch 31,
Non‐GAAP Financial Measures
30
Reconciliation of Average Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense
Years ended December 31,2008 2009 2010 2012
(In thousands except for operating daysand operating margins)
Contract drilling revenue $622,727 $236,315 $316,384 $484,651 $529,719
Contract drilling operating cost 312,907 140,080 186,813 269,899 289,524
Operating profit from contractdrilling $309,820 $96,235 $129,571 $214,752 $240,195
Add:
Elimination of intercompany rig profit and bad debt expense 29,381 1,549 9,158 19,900 15,583
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense
339,201 97,784 138,729 234,652 255,778
Contract drilling operating days 37,745 14,183 22,367 27,619 26,704
Average daily operating margin before elimination of intercopmany rig profit and bad debt expense
$8,987 $6,894 $6,202 $8,496 $9,578
2011
Midstream Reconciliation of EBITDA(Before Intercompany Eliminations)
31
Total Midstream Income (Loss)Before Intercompany Eliminations $ 7,126 $ 19,267 $ 19,555 $ 8,237 $ 15,636 $ 6,626 $ (24,159) $ 8,799
(Gain) Loss on Disposition of Assets ‐‐‐ ‐‐‐ 81 313 ‐‐‐ (97) (465) 302Depreciation and Amortization 16,104 15,385 16,101 23,110 33,191 40,434 43,676 45,715Impairments ‐‐‐ ‐‐‐ ‐‐‐ 1,278 ‐‐‐ 7,068 26,966 ‐‐‐Segment EBITDA Before Intercompany Eliminations * $ 23,230 $ 34,652 $ 35,737 $ 32,938 $ 48,827 $ 54,031 $ 46,018 $ 54,816
Segment EBITDA Before Intercompany EliminationsYears ended December 31,
($ In Millions) 2009 2010 2011 2012 2013 2014 2015 2016
*Excludes depreciation, allocated interest, and corporate G&A
Derivative Summary
32
Crude 2017 2018Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
CollarsVolume (Bbl) ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Floor ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Ceiling ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐
3‐Way CollarsVolume (Bbl) 337,500 341,250 345,000 345,000 90,000 91,000 92,000 92,000Weighted Avg Floor $49.79 $49.79 $49.79 $49.79 $50.00 $50.00 $50.00 $50.00Weighted Avg Subfloor $39.58 $39.58 $39.58 $39.58 $40.00 $40.00 $40.00 $40.00Weighted Avg Ceiling $60.98 $60.98 $60.98 $60.98 $56.65 $56.65 $56.65 $56.65
SwapsVolume (Bbl) ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Swap ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐ ‐‐
Natural Gas 2017 2018Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
CollarsVolume (MMBtu) 1,800,000 1,820,000 1,840,000 620,000 ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Floor $2.88 $2.88 $2.88 $2.88 ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Ceiling $3.10 $3.10 $3.10 $3.10 ‐‐ ‐‐ ‐‐ ‐‐
3‐Way CollarsVolume (MMBtu) 1,350,000 1,365,000 1,380,000 1,990,000 5,400,000 1,820,000 1,840,000 1,840,000Weighted Avg Floor $2.50 $2.50 $2.50 $2.81 $3.29 $3.00 $3.00 $3.00Weighted Avg Subfloor $2.00 $2.00 $2.00 $2.23 $2.63 $2.50 $2.50 $2.50Weighted Avg Ceiling $3.32 $3.32 $3.32 $3.53 $4.07 $3.51 $3.51 $3.51
SwapsVolume (MMBtu) 6,300,000 6,370,000 6,440,000 5,830,000 1,800,000 1,820,000 1,840,000 1,840,000 Weighted Avg Swap $3.04 $3.04 $3.04 $2.99 $3.01 $3.01 $3.01 $3.01
Q2 2017 Economic Prices
33
CrudeNatural
Gas MB C2 MB C3BBL MB
C3 MB NC4 MB iC4 MB C5+ CW C2 CW C3 CW NC4 CW iC4 CW C5+
2017 $51.048 $3.334 $0.261 $0.662 $27.815 $0.783 $0.773 $1.123 $0.210 $0.629 $0.734 $0.842 $1.132
2018 $51.498 $3.092 $0.242 $0.668 $28.060 $0.790 $0.780 $1.133 $0.195 $0.634 $0.741 $0.850 $1.142
2019 $50.838 $2.864 $0.224 $0.660 $27.700 $0.779 $0.770 $1.119 $0.181 $0.626 $0.731 $0.839 $1.127
2020 $50.883 $2.838 $0.222 $0.660 $27.724 $0.780 $0.770 $1.120 $0.179 $0.627 $0.732 $0.840 $1.128
2021 $51.521 $2.887 $0.226 $0.668 $28.072 $0.790 $0.780 $1.134 $0.182 $0.634 $0.741 $0.850 $1.142
Thereafter $51.521 $2.887 $0.226 $0.668 $28.072 $0.790 $0.780 $1.134 $0.182 $0.634 $0.741 $0.850 $1.142
Strip Case*
*Strip prices as of 5/25/2017.
June 7, 2017
Bank of America Merrill LynchEnergy Credit Conference