IPAA Oil & Gas Investment Symposium - Unit Corporation - A … · · 2018-04-10• Retains 50%...
Transcript of IPAA Oil & Gas Investment Symposium - Unit Corporation - A … · · 2018-04-10• Retains 50%...
2
Forward Looking Statement
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.
3
A Diversified Energy Company
10
10
6
55
14
Casper Casper
Arkoma Basin
Marcellus
North La/ East Texas Basin
Gulf Coast Basin
Anadarko Basin
Permian Basin
95 Unit Rigs
E&P Operations
Midstream Operations
Office Location
• Tulsa based, incorporated in 1963
• Integrated approach to business allows Unit to capture margin from each business segment
Houston Houston
Oklahoma City
Oklahoma City
Tulsa HeadquartersTulsa Headquarters
PittsburghPittsburghMississippianBasin
4
Investment Highlights
• Opportunity-rich upstream portfolio with compelling economics provides optionality
• Upstream capital allocated to areas generating highest rates of return in the Company’s portfolio
• Contract drilling segment activity level rebounding• Sale of 50% equity stake in Superior highlights asset value
and provides growth capital to benefit all three Unit Business segments
• Conservative balance sheet with corporate net debt < 2X EBITDA and philosophy of spending within cash flow
5
Core Upstream Producing Areas
GasNGLs
Oil
54%28%
18%
Q1 2018 Daily Production: 46.5 MBoe/d
Mid Continent Region
Upper Gulf Coast Region
Wilcox
Hoxbar/STACK
Granite Wash
Key focus areas include:Gulf Coast: Wilcox (Southeast Texas)
Mid-Continent: Granite Wash (Texas Panhandle) Hoxbar (Western Oklahoma) STACK (Western Oklahoma)
0
10
20
30
40
50
60
2013 2014 2015 2016 2017 2018 est
Natural Gas Oil / NGLs
47-4846 475055
44
Average Production (MBoe/d)Net Wells Drilled:
91 121 35 10 26 ~34
6
Natural Gas Oil / NGLs
Track Record of Reserve Growth
-150%
0%
150%
300%
450%
20
01
20
02
20
03
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
(119%)
0
30
60
90
120
150
180
20
01
20
02
20
03
20
04
20
05
20
06
20
07
20
08
20
09
20
10
20
11
20
12
20
13
20
14
20
15
20
16
20
17
Annual Reserve Replacement
161%171% 176%202% 204%
261%221%
186%
Average: 176%
113%
116
160
6979
8695 96 104
150
337%
179Proved Reserves (MMBoe)
135118
150
58484542
285%
166%169%161%
(1%)
300%
7
Core Area Cash Margins
Note: Assumes 6:1 gas to oil ratio. Adjusted base represents the weighted average commodity price per Mcfe of the area’s production (using WTI, Henry Hub and Mont Belvieu propane for NGL). Adjusted Base also includes 50% of applicable midstream margin for Granite Wash and Wilcox.
% Gas 17% 25% 42% 60% 63% 99%
$7.03
$4.88
$3.87
$2.93 $2.21
$1.33
$1.56
$1.17
$1.18
$0.97
$1.09
$0.88
$0.42
$0.70
$0.81
$0.87 $1.29
$0.80
Adjusted Base$9.01
Adjusted Base$6.75
Adjusted Base$5.86
Adjusted Base$4.76 Adjusted Base
$4.59
Adjusted Base$3.01
Gas Base, $2.85
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
SOHOT STACK Oil STACKCondensate
Wilcox Granite Wash STACK Dry Gas
$/M
cfe
Differential - Adjusted
LOE & Taxes
Cash Margin
*Differentials adjusted forproduction stream mix
*
Type CurveMarchand
5,000’Marchand
7,500’
IP - 30 (Boe/d) 667 933
ROR 119% 171%
EUR (Mboe) 524 737
% Liquids 83% 83%
Lateral Length 5,000’ 7,500’
Well Cost ($mm) $5.4 $6.7
8
1Lease
SpudDate
IP-30Boe/d % Oil
LateralLength
Schmidt #1-10H Unit 9/17 687 80 5,000Nina #1-22H Unit 8/17 1,124 76 4,855McConnell #1-11H Unit 10/17 1,091 63 4,943Schenk Tr. #1-17HXL Unit 11/17 2,343 79 7,825Liv. Land #1HXL Unit 1/18 499 72 7,985Torralba 10-5-8 #1H Kaiser 1/17 575 70 4,839Amanda 21-6-8 #1H Kaiser 3/17 540 71 5,050
1
2
3
5
Marchand VerticalMarchand Horizontal
4
Denotes Unit non-op working interest. 6
7
0%
50%
100%
150%
200%
250%
300%
350%
$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50
IRR
%
Marchand 5k Marchand 7.5k
Single Well Economics
Operator
SOHOT – Low Cost, High ROR Oil Play
2
6
7
5
3
4
1 5/1/2018 Strip Price Deck with 1st Production Starting 5/1/2018.See Q2 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
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Geology• Marchand stacked lenses provide
multiple oil drilling targets• Medrano proved gas potential
Land• 23,000 contiguous net acres• 65% HBP• Majority operated• Working interest 50-70%• 40 to 50 location inventory steady with
continued acquisition of bolt on acreage• Waterflood potential
Operations• Running one Unit Drilling rig • Incremental optimization of drilling and
completion process has kept cost low without sacrificing EUR
• Extended laterals (XL) improving capital efficiency
SOHOT – Growing Oil Production and Improving Capital Efficiency
Quarterly Net BOE
0
100,000
200,000
300,000
400,000
500,000
600,000
Q1'17 Q2'17 Q3'17 Q4'17 Q1'18
Gas NGL Oil
WellSpudDate
IP-30MMcfe/d
Gas%
LateralLength
Dixon 5554 XL #1H Unit 2/16 12.5 47% 7,503’
Dixon 5554 EXL #4H Unit 2/17 7.5 47% 7,474’
Carr 1357 EXL #1H Unit 3/17 14.9 45% 7,891’
Carr 1357 EXL #2H Unit 5/17 9.2 45% 7,663’
Francis 5859 EXL #2H Unit 9/17 8.1 49% 9,442’
Dixon 5554 EXL #5H Unit 6/17 2.1 64% 7,802’
Meek 6836H Unit 5/14 5.7 61% 4,375’
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Granite Wash – Low Risk Wet Gas Condensate Play with NGL Price Upside
Type CurveGranite
Wash C1Granite Wash G
Granite Wash B
IP - 30 (Mcfe/d) 9,960 9,000 7,902ROR 43% 44% 26%EUR (Bcfe) 7.6 14.2 7.1% Gas 48% 77% 52%Lateral Length 7,500’ 7,500’ 7,500’Well Cost ($mm) $6.2 $6.2 $6.2
GW C1
Single Well Economics
Unit Tecolote Jones FourPoint Le Norman BPGW B
1
GW G
2
3
4
5
6
7
1 23 4
5
6
7
0%
20%
40%
60%
80%
100%
120%
$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50
IRR %
Granite Wash C1 Granite Wash G Granite Wash B
Operator
1 5/1/2018 Strip Price Deck with 1st Production Starting 5/1/2018.See Q2 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
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Granite Wash – Competitive Advantages Drive Differentiated Value
Gas NGL Oil
Geology• 11 Stacked Granite Wash lenses
significantly improves capital efficiency• Sands present across acreage
Land• 9,000 net largely contiguous acres allow
for extended lateral (XL) drilling• 90% HBP and Operated• Average working interest 90%• 150-200 potential XL locations• Continuing to expand position
Operations/Infrastructure/Processing• Running one Unit Drilling rig• Incremental process improvements
continue to decrease drilling days• SWD network lowers disposal costs 80%• Water recycling pits lower frack costs• Electricity across field lowers lifting costs• Superior processes the gas improving
cash margin
Buffalo Wallow Quarterly Net MMcfe
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
Q1'17 Q2'17 Q3'17 Q4'17 Q1'18
Type CurveOil
WindowCondensate
WindowDry Gas* Window
IP - 30 (Boe/d, Mcfe/d*) 1,706 1,773 15,415*
ROR 108% 68% 15%
EUR (Mboe/Bcfe*) 1,939 1,958 18.9*
% Liquids/Gas 65% 58% 99%
Lateral Length 10,000’ 10,000’ 10,000’
Well Cost ($mm) $10.7 $10.7 $10.9
Lease Operator Spud DateIP-30
MMcfe/dGas %
Lateral Length
Anderson Half Continental 2/2016 17.1 99% 9,676Edith Mae Continental 6/2016 23.6 99% 9,743Abbott Com Cimarex 8/2017 Flowing Back 10,385Hicks BIA Marathon 7/2017 14.8 99% 9,652Reece Jane Continental 2/2017 16.6 100% 9,898Wyatt Continental 8/2016 16.5 100% 8,805Eagle Continental 9/2017 WOC 9,679Gripe FIU Continental 8/2017 16.0 100% 10,175
Lease Operator Spud DateIP-30Boe/d
Liquids %
Lateral Length
Jordan Devon 4/2017 1,636 51% 10,050ML Devon 9/2016 1,766 48% 4,676Carpenter Cimarex 10/2017 WOC 4,786Privott Devon 10/2016 4,308 57% 10,112Lorene Continental 7/2017 5,483 30% 10,186Geronimo 89 Energy 6/2017 895 58% 4,797Rafter J Ranch Marathon 7/2017 1,017 27% 4,111
12
Single Well Economics
STACK Core - Provides High ROR Oil/Wet Gas with Dry Gas Optionality
1
2
3
4
5
6
7
9
8
OilCondensate
Dry Gas
Unit’s Acreage
Meramec
Woodford
1
3
2
4
56
8
9
10
11
12
13
14
15
7
10
Denotes Unit working interest
0%
50%
100%
150%
200%
250%
$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50
IRR
%
Stack Condensate Stack Dry Gas Stack Oil
11
12
14
13
15
1 5/1/2018 Strip Price Deck with 1st Production Starting 5/1/2018.See Q2 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
Type CurveSTACK ExtMeramec
STACKOsage
IP - 30 (Boe/d) 1,040 1,203
ROR 77% 35%
Total EUR (Mboe) 920 956
% Liquids 63% 57%
Lateral Length 5,000’ 5,000’
Well Cost ($mm) $6.2 $7.3
13
Lease Operator Spud DateIP-30Boe/d
Liquids %
Lateral Length
Cox Tapstone 9/2017 1,583 20% 10,009Rebecca Tapstone 11/2017 788 50% 10,130Randi Tapstone 7/2017 678 43% 10,178Bond Comanche 6/2017 1,305 40% 4,300Walters Newfield 7/2017 1,598 77% 10,179Ward Comanche 106/2015 627 75% 4,162Medrill Sandridge 10/2016 1,164 85% 4,681Schoeppel Chesapeake 7/2016 865 54% 4,764McConnell Comanche 6/2016 532 46% 4,493Drinnon Tapstone 5/2016 793 22% 4,111Olive Lee Devon 3/2014 1,755 19% 4,594Bivens Tapstone 11/2017 1,363 48% 4,436
Lease Operator Spud DateIP-30
Mmcfe/dGas %
Lateral Length
Stephen Chesapeake 9/2016 4.6 97% 4,925Tucker Council Oak 6/2017 8.1 99% 4,378
10
5
6
7
8
11 13
9
4
3
Oil
Condensate
Dry Gas
12
1
Denotes Unit working interest
Unit’s Acreage
Meramec
Osage
1
2
3
4
5
6
7
8
9
10
1
23
45
6
7
89
0%
50%
100%
150%
200%
$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50
IRR %
Stack Ext Meramec Stack Osage
Single Well Economics
STACK West – Successful Extension of Meramec and Potential for Osage Development
11
12
13
14
12
11
13
10
14
1 5/1/2018 Strip Price Deck with 1st Production Starting 5/1/2018.See Q2 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
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STACK – Growing into Core Areafor Unit Petroleum
Gas NGL Oil
Quarterly Net BOE
Geology• Stacked drilling targets in Osage,
Meramec and Woodford• Red Fork Potential in some areas• Sands consistently present across play
Land• 17,000 net acres in STACK(1)/STACK
West(2)
• 85% HBP provides hydrocarbon mix optionality
• 100 - 150 potential operated locations with working interest of 40 - 60%
• 500 - 900 potential non-operated locations with working interest of ~5%
Operations• Running one Unit Drilling rig• Participating ~50 non-op wells in 2018• Focused on oil and wet gas window• Dry gas delayed until gas margins and
takeaway capacity improves
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
Q1'17 Q2'17 Q3'17 Q4'17
Potential location counts based upon:(1) 4-6 wells/section(2) 2-4 wells/section
JASPER
POLK
3D AREA494 mi.²
HARDIN
Prior Years DrillingHorizontal Wells
TYLER
Gilly Field
Wilcox – Conventional Stacked Over-Pressured Intervals Provide Low Cost Homerun Potential
15
$/MCFE
Overall Wilcox Drilling Program Results Drilled 170 operated wells since 2003
(160 vertical, 10 horizontal) Program ROR > 80% Operated with working interest ~ 92% Production: ~ 110 MMcfe/d (42% liquids) Running one Unit Drilling rig
Gilly Field – World Class Wet Gas Reservoir 500 Bcfe stacked pay gas resource Cumulative production ~ 115 Bcfe Average EUR of 10-20 Bcfe per well Typical well ~ $6 MM cost, ROR > 100%
Unit’s Wilcox Competitive Advantages Premium Gulf Coast pricing for oil and gas Wet Gas/Condensate provides margin uplift Large 3D seismic database provides consistent
stream of exploratory prospect ideas Conventional over-pressured reservoirs provide
homerun potential at low acreage costs0.40
0.80
1.20
1.60
2.00
0
10
20
30
40
2012 2013 2014 2015 2016 2017 2018Projected
Gas Oil NGLs LOEX ($/MCFE)
Wilcox Annual ProductionBCFE
Wilcox – Exceptional Recompletion & Workover Results
16
2017 Composite Gross Production from Recompletions and Workovers28 Recompletions & 13 Workovers Total Cost: $15MM
Start of Year9.0 MMcfd300 bopd
End of Year34.0 MMcfd
900 bopd• 2016 recompletion/workover
results20 recompletions7 workoversTotal cost: $10 millionProduction increase >1,000%
• Remaining recompletion inventory ~ 80 zones
• Continue to add to inventory with new drilling
Wilcox Trend Provides an Extensive Play Area
Wilcox Strategy for Future Growth Continue development of Gilly Field
area with vertical and horizontal drilling and over 80 stacked pay recompletion/workover opportunities in existing wells
Drill and delineate inventory of exploratory prospects with homerun potential (e.g. Wing/Cherry Creek/Brandt prospects)
Utilize horizontal drilling to extend field boundaries and accelerate reserve recovery (e.g. NE Segno/Village Mills Fields)
18
Rig Fleet Presence in Key Regions
10
10
55
146
Area # of RigsMid‐Continent 18
Bakken 4Niobrara 1Permian 7Pinedale 1Gulf Coast 2
Total 33
Current Rigs Operating(1)
95 rig fleet
69% electric 54% 1,500 HP or greater 35 equipped with skidding or walking systems 26 additional can be skidded
35% total fleet utilization at present All ten BOSS rigs operating Entered into long-term contracts for
11th and 12th BOSS rigs
20 ≤800 HP: 21%71 1,000-1,700 HP: 75%
4 ≥2,000 HP: 4%
(1) As of May 30, 2018.
19
SCR Rigs Continue to Make anImportant Contribution
0
5
10
15
20
25
30
35
40
May 5, 2016 Dec. 31, 2016 Sept. 4, 2017 Dec. 31, 2017 May 30, 2018
A/C SCR
• At industry trough – 13 drilling rigs operating
• Currently, 33 drilling rigs operating
• All BOSS rigs operating
• 23 SCR rigs operating7
12
26
21
6
910 10
22
10
20
Average Dayrates and Margins (1)
Average Rig U
tilization
Mar
gins
and
Day
rate
s
$0
$5,000
$10,000
$15,000
$20,000
2014 2015 2016 2017 Q1'18
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).
• Decline in dayrates lagged utilization decrease due to long-term contract roll-off
• Utilization increased from low in Q2 2016
• Margins improved from Q2 2017 forward
21
The BOSS Drilling Rig
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 availablewith one pump
Environmentally Conscious Dual-fuel capable
engines Compact location
footprint
All ten BOSS rigs currently under contract
11th BOSS rig under construction
12th BOSS rig under contract (components being assembled)
22
• Retains 50% equity interest• Received $300 million• Retains operational control of
Superior Pipeline
Superior Joint Venture Overview
• Acquired 50% equity interest• $300 million consideration• Non-managing member
• Access to additional growth capital• To be governed by new board of directors
• Four directors from Unit• Four directors from SP Investor Holdings
Implied Valuation of$600 million*
SP Investor Holdings LLC50% 50%
* 2017 Adjusted EBITDA of $51.7 million.
23
(in thousands except leverage ratios) 3/31/2018 Pro‐Forma
Long term debtBank $ 147,700 $ 0Bonds (net of discount & issuance cost) 642,822 642,822
Total $ 790,522 $ 642,822
Cash 752 150,444Unused bank commitment 325,513 423,213
Total liquidity (1) $ 326,265 $ 573,657
Adjusted EBITDA $ 328,688 $ 302,927
Net debt leverage ratio 2.40x 1.63x
Superior Transaction
Unit Corporation Pro-Forma
(1) On May 10, 2018, Superior entered into a five year $200 million senior secured revolving credit facility with an option to increasethe credit amount up to $250 million, subject to certain conditions.
24
Midstream Core Operations
Appalachia 66,000+ dedicated acres 53 miles of gathering pipeline Q1’18 average gathered volume
of 106.5 MMcf/d
TulsaHeadquarters
Hemphill
Reno
Bellmon
Segno
Processing facilities
Gathering systems
Panola
Key Metrics
• 22 active systems
• Three natural gas treatmentplants
• 340 MMcf/d processing capacity
• Q1’18 average processing volume of 151 MMcf/d
• Approx. 1,452 miles of pipeline
East Texas 62 miles of gathering
pipeline 120 MMcf/d dehy capacity Q1’18 average gathered
volume of 84.9 MMcf/d
Texas Panhandle 47,000+ dedicated acres 135 MMcf/d processing capacity 331 miles of gathering pipeline
Northern Oklahoma and Kansas 2,000,000+ dedicated acres 193 MMcf/d processing capacity 609 miles of gathering pipeline
Central & Eastern OK 62,000+ dedicated acres 12 MMcf/d processing capacity 397 miles of gathering pipeline
PittsburghRegional office
Pittsburgh Mills
Brook Field
Snow Shoe
Bruceton Mills
25
Midstream Segment Contract Mix
Contract Mix Based on Margin
Fee BasedCommodity Based
85%41%
59%
15%
Contract Mix Based on Volume
Fee BasedCommodity Based
49%35%
65%51%
2010 Q1 ‘2018
Unit vs. 3rd Party Margin Contribution
3rd PartyUnit
41% 40%60%59%
26
Debt Structure – No Near-Term Maturities
* Drilling rigs are not included in borrowing base.
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 2018) * Borrowing Base and
Elected Commitment $525/$475 million
Outstanding(2) $147.7 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, 2018.(3) Pro forma after close of Superior transaction.
Ratings S&P Moody’s FitchCorporate B+ B2 B+Senior Subordinated Notes BB- B3 BB-
3/31/20186.01x(1,2)
3/31/2018 Actual2.18x(1,2)
0.45x(1,2)
Pro forma3.44x (3)
0.0 (3)
Pro forma$425 million (3)
$0 (3)
27
Segment Contribution
Oil and Natural Gas Contract Drilling Midstream
Revenues ($ millions) Adjusted EBITDA ($ millions)(1)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
2014 2015 2016 2017 Q1'18
$0
$200
$400
$600
$800
2014 2015 2016 2017 Q1'18
$205
$1,573
$854
$602
$740
$787
$410
$252
$313
$89
(1) See Non-GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html).
28
Operating Segment Capital Expenditures (1)
$0
$500
$1,000
$1,500
2013 2014 2015 2016 2017 2018 Forecast
Oil and Natural Gas Contract Drilling Midstream
(In Millions)
(1) Net of acquisitions and plugging liability revisions.
30
Non-GAAP Financial Measures - Corporate
Adjusted EBITDA
Years endedDecember 31,
($ In Millions) 2018 2014 2015 2016 2017
Net Income (Loss) $16 $8 $136 ($1,037) ($136) $118Income Taxes 14 3 87 (627) (71) (58)Depreciation, Depletion and Amortization
47 57 403 353 208 209
Impairments --- --- 158 1,635 162 ---Interest Expense 9 10 17 32 40 38 (Gain) loss on derivatives (15) 7 (30) (26) 23 (15)Settlements during the period of matured derivative contracts
(1) (2) (6) 47 10 ---
Stock compensation plans 4 7 24 21 14 18 Other non-cash items 1 (1) 5 3 3 3 (Gain) loss on disposition of assets --- --- (9) 7 (3) ---Adjusted EBITDA $75 $89 $785 $408 $250 $313
2017
Three months endedMarch 31,
31
Non-GAAP Financial Measures - Segments
Segment Cash Operating Margin
(1) After intercompany eliminations and does not include allocation of G&A expense.
Unit PetroleumIncome (Loss) Before Income Taxes (1) $ 36 $ 36 $ 199 $ (1,631) $ (102) $ 125
Depreciation, Depletion and Amortization 22 31 276 252 114 102Impairment of Oil and Natural Gas Properties --- 77 1,599 162 ---
Adjusted EBITDA $ 58 $ 67 $ 552 $ 220 $ 174 $ 227
Unit DrillingIncome (Loss) Before Income Taxes (1) $ (5) $ 1 $ 42 $ 45 $ (13) $ (4)
Depreciation and Impairment 13 13 160 64 47 56Adjusted EBITDA $ 8 $ 14 $ 202 $ 109 $ 34 $ 52
Superior PipelineIncome (Loss) Before Income Taxes (1) $ 2 $ 3 $ 2 $ (30) $ 2 $ 8
Depreciation, Amortization and Impairment 11 11 48 71 46 44Adjusted EBITDA $ 13 $ 14 $ 50 $ 41 $ 48 $ 52
($ In Millions) 2018 2014 2015 2016 20172017
Years endedDecember 31,
Three months endedMarch 31,
32
Non-GAAP Financial MeasuresReconciliation of Average Contract Drilling Daily Operating Margin
Before Elimination of Intercompany Rig Profit and Bad Debt Expense
(In thousands except for operating daysand operating margins) 2017 2014 2015 2016 2017
Contract drilling revenue $37,185 $45,989 $476,517 $265,668 $122,086 $174,720
Contract drilling operating cost 29,227 31,667 274,933 156,408 88,154 122,600
Operating profit from contract drilling $7,958 $14,322 $201,584 $109,260 $33,932 $52,120
Add:
Elimination of intercompany rig profit and bad debt expense
- 434 29,343 3,991 235 1,620
Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense
7,958 14,756 230,927 113,251 34,167 53,740
Contract drilling operating days 2,291 2,849 27,516 12,681 6,374 10,964
Average daily operating margin beforeelimination of intercompany rig profit and bad debt expense
$3,474 $5,179 $8,392 $8,931 $5,360 $4,901
2018
Years endedDecember 31,
Three months endedMarch 31,
33
Income (loss) before income taxes $35.2 $1.5 $4.6 ($29.8) $11.5
Pro-forma Intercompany impact 0.2 --- (0.9) 0.7 ---
Pro-forma Interest impact --- --- (0.5) 2.3 1.8
Pro-forma income (loss) before income taxes $35.4 $1.5 $3.2 ($26.8) $13.3
Pro-forma taxes 9.8 0.4 0.4 (7.4) 3.2
Pro-forma net income (loss) 25.6 1.1 2.8 (19.4) 10.1
Net income attributable to non-controllinginterest
--- --- (1.6) --- (1.6)
Net income attributable to Unit $25.6 $1.1 $1.2 ($19.4) $8.5
Pro-forma Reconciliation
Pro-forma Reconciliation of First Quarter 2018 Results as if Superior Transaction Occurred 1-1-2018
(In millions) ContractDrilling Midstream Other
TotalConsolidated
Oil and Natural Gas
34
Derivative Summary
2018 2019 2020Q2 Q3 Q4
CRUDE:CollarsVolume (Bbl) -- -- -- -- --Weighted Avg Floor -- -- -- -- --Weighted Avg Ceiling -- -- -- -- --3-Way CollarsVolume (Bbl) 182,000 184,000 184,000 730,000 --Weighted Avg Floor $47.50 $47.50 $47.50 $57.50 --Weighted Avg Subfloor $37.50 $37.50 $37.50 $47.50 --Weighted Avg Ceiling $56.08 $56.08 $56.08 $71.90 --SwapsVolume (Bbl) 364,000 368,000 368,000 -- --Weighted Avg Swap $53.52 $53.52 $53.52 -- --
NATURAL GAS:CollarsVolume (MMBtu) 2,730,000 2,760,000 -- -- --Weighted Avg Floor $2.67 $2.67 -- -- --Weighted Avg Ceiling $2.97 $2.97 -- -- --3-Way CollarsVolume (MMBtu) 1,820,000 1,840,000 1,840,000 -- --Weighted Avg Floor $3.00 $3.00 $3.00 -- --Weighted Avg Subfloor $2.50 $2.50 $2.50 -- --Weighted Avg Ceiling $3.51 $3.51 $3.51 -- --SwapsVolume (MMBtu) 3,640,000 3,680,000 2,150,000 -- --Weighted Avg Swap $2.99 $2.99 $3.01 -- --Basis SwapsVolume (MMBtu) 2,730,000 2,760,000 2,450,000 18,250,000 10,950,000Weighted Avg Swap ($0.48) ($0.48) ($0.52) ($0.43) ($0.28)
PROPANE:SwapsVolume (Bbl) 136,500 138,000 -- -- --Weighted Avg Swap $32.144 $32.144 -- -- --
CrudeNatural
Gas MB C2 MB C3MB C3 $ per barrel MB NC4 MB iC4 MB C5+ CW C2 CW C3 CW NC4 CW iC4 CW C5+
2018 $66.545 $2.851 $0.282 $0.876 $36.786 $0.973 $1.089 $1.524 $0.101 $0.764 $0.789 $1.038 $1.485
2019 $61.403 $2.741 $0.272 $0.808 $33.943 $0.898 $1.005 $1.406 $0.097 $0.705 $0.728 $0.958 $1.370
2020 $56.464 $2.708 $0.268 $0.743 $31.213 $0.826 $0.924 $1.293 $0.096 $0.648 $0.669 $0.881 $1.260
2021 $53.259 $2.726 $0.270 $0.701 $29.441 $0.779 $0.872 $1.219 $0.096 $0.612 $0.631 $0.831 $1.188
2022 $51.406 $2.779 $0.275 $0.677 $28.417 $0.752 $0.842 $1.177 $0.098 $0.590 $0.609 $0.802 $1.147
Thereafter $51.406 $2.779 $0.275 $0.677 $28.417 $0.752 $0.842 $1.177 $0.098 $0.590 $0.609 $0.802 $1.147
35
Q2 2018 Economic Prices
Strip Case*
*Strip prices as of 5/1/2018.