Bank of America Merrill Lynch Energy Credit Conference
June 5, 2019
Forward Looking Statement
NYSE: UNT 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 and other risks disclosed under “Risk Factors” in the Company’s most recent Form 10-K and Form 10-Q. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. 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. This presentation may contain certain terms, such as locations and estimated ultimate recovery (“EUR”) and other similar terms that describe estimates of potential wells and potentially recoverable hydrocarbons that SEC rules prohibit from being included in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and may not constitute “reserves” within the meaning of SEC rules and accordingly, are subject to substantially greater risk of being actually realized. These estimates are based on the Company’s existing models and internal estimates. 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 EBITDA, adjusted EBITDA, and certain operating margins and 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.
A Diversified Energy Company
NYSE: UNT 3
11
8
4
24
10
Casper
Arkoma Basin
Marcellus
North La/ East Texas Basin
Gulf Coast Basin
Anadarko Basin
Permian Basin
57 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
Oklahoma City
Tulsa Headquarters
PittsburghMississippianBasin
Investment Highlights
NYSE: UNT 4
• Diversified energy company with upstream, midstream, and drilling rig segments and track record of growing with a capital budget in-line with anticipated cash flow
• Upstream portfolio of high return drilling opportunities, growing oil and liquids component, and attractive full cycle economics
• Midstream assets which enhance UNT’s all-in drilling economics and provide predictable cash flow stream supported by UNT and third party volumes
• High spec A/C rig fleet fully contracted and relevant SCR rig presence
• History of disciplined capital stewardship • Target leverage of
Core Upstream Producing Areas
NYSE: UNT 5
Mid Continent Region
Upper Gulf Coast Region
Wilcox
Hoxbar/STACKGranite Wash
Key focus areas include:Gulf Coast: Wilcox (Southeast Texas)
Mid-Continent: Granite Wash (Texas Panhandle) Hoxbar & Red Fork (Western Oklahoma) STACK (Western Oklahoma)
GasNGLs
Oil
54%29%
17%Q1 2019 Daily Production:
45.8 MBoe/d
0102030405060
2015 2016 2017 2018 2019 est
Natural Gas Oil / NGLs
48-49474755
44
Average Production (MBoe/d)Net Wells Drilled:
35 10 26 33 30-40
Reserve Detail
NYSE: UNT 6
PDPPUD
PDNP
58%30%
12%
Net Proved Reserves
• Reserve summary, as of 12/31/2018, audited by Ryder Scott Company, L.P.• Reserves up 7% Y/Y• PDP up 2% Y/Y• PV-10 up 23% Y/Y
GasNGLs
Oil
56%30%
14%
Proved Reserves Allocation PV-10
Oil (Mbbls) Nat Gas (MMcf) NGL (Mbbls) Total (Mboe) PV-10 ($MM)PDP 13,248 301,948 28,171 91,743 $831PDNP 1,944 75,268 5,344 19,833 $102PUD 7,366 158,747 14,281 48,105 $173Total Proved 22,558 535,963 47,796 159,681 $1,106
PDP
PDNP
PUD75%
9%
16%
Track Record of Reserve Growth
NYSE: UNT 7
0
30
60
90
120
150
180
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
Natural Gas Oil / NGLs
-150%
0%
150%
300%
450%
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
(119%)
Annual ReserveReplacement 161%171% 176%
202% 204%261%
221%186%
Average: 176%
113%
116
160
6979 86
95 96104
150
337%
179
Proved Reserves(MMBoe)
135118
150
58484542
285%
166%169%161%
(1%)
300%
160
158%
Core Area Cash Margins
NYSE: UNT 8
Note: assumes 6:1 gas to oil ratio. Production is based upon actual (April 2018 through April 2019) or average type curves for the respective plays. The adjusted base prices represent the weighted average commodity price perMcfe for each area’s production (using WTI, Henry Hub and Mont Belvieu propane as a proxy for NGL prices) and are based on the May 20, 2019 strip. Differentials are adjusted to each area’s production mix as of May 14, 2019. Differentials for the STACK Dry Gas and Granite Wash are estimated from basis futures and index pricing as of May 28, 2019 and assume a 75% reduction of marketing fees after the commissioning of the Midship Pipeline. Lease operating expenses are based upon area specific operating cost models used in preparation the 2018 Annual Proved Reserve Report and include gas transportation costs updated as of November 27, 2018. Taxes are calculated using production and pricing described herein with Texas severance taxes adjusted for high cost tax rates. The adjusted base also includes 50% of the applicable midstream margin for Granite Wash and Wilcox.
% Gas 23% 35% 40% 43% 65% 63% 100%
*Differentials adjusted for production stream mix
$5.63
$4.04 $3.73 $3.07
$2.26 $1.76
$1.29
$1.37
$1.16 $1.43
$1.09
$1.00
$1.03
$0.93
$0.53
$0.70 $0.86
$0.79
$0.53 $0.95
$0.66
Adjusted Base$7.53
Adjusted Base$5.90
Adjusted Base$6.02
Adjusted Base$4.95
Adjusted Base$3.79
Adjusted Base$3.75
Adjusted Base$2.88
Gas Base, $2.73
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
SOHOT STACK Oil Red Fork STACKCondensate
Wilcox Granite Wash STACK Dry Gas
Differential - Adjusted*
LOE & Taxes
Cash Margin
SOHOT – Low Cost, High ROR Oil Play
NYSE: UNT 9
Unit PetroleumCaminoEcho E&P LLCKaiser- FrancisLimerock Resources
Denotes Unit Non-Opworking interest
Marchand Horizontal
Unit PetroleumSchmidt 1-10HIP: 687 Boe/d 80% Oil
1Unit PetroleumNina 1-22HIP: 1,124 Boe/d 76% Oil
2Unit PetroleumMcConnell 1-11HIP: 1,271 Boe/d 63% Oil
3Unit PetroleumSchenk Trust 1-17HXLIP: 2,349 Boe/d 79% Oil
4Unit PetroleumSchenk Trust 2-17HXLIP: 1,463 Boe/d 79% Oil
5
Unit PetroleumSchenk Trust 3-17HXLIP: 1,470 Boe/d 75% Oil
6
Unit PetroleumLivingston Land 1HXLIP: 565 Boe/d 72% Oil
7
Unit Petroleum5D 13/12 1HXLIP: 520 Boe/d 88% Oil
8
Kaiser FrancisTorralba 10-5-8 1HIP: 578 Boe/d 70% Oil
9
Kaiser FrancisAmanda 21-6-8 1HIP: 540 Boe/d 71% Oil
10
Single Well Economics
SOHOT – Low Cost, High ROR Oil Play
NYSE: UNT 10
Unit PetroleumCaminoEcho E&P LLCKaiser- FrancisLimerock Resources
Marchand Horizontal
1 5/20/2019 Strip Price Deck with 1st Production Starting 4/1/2019.See Q2 2019 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
Type CurveMarchand
5,000’Marchand
7,500’
IP - 30 (Boe/d) 699 979
ROR (1) 101% 146%
EUR (Mboe) 619 881
% Liquids 77% 77%
Well Cost ($mm) $5.3 $6.6
0%
50%
100%
150%
200%
250%
300%
350%
$45 / $2.50 5/20/19 Nymex $65 / $3.50 $75 / $4.00
IRR
%
5,000' Lateral 7,500' Lateral
SOHOT – Growing Oil Productionand Improving Capital Efficiency
NYSE: UNT 11
Yearly Net BOE
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
1,800,000
2,000,000
2017 2018
Gas NGL Oil
Geology• Marchand stacked lenses provide
multiple oil drilling targets• Medrano proved gas potential
Land• 31,000 net acres• 84% HBP• Majority operated• Average working interest approx.
89%• 40 to 50 location inventory
Operations• Running two Unit Drilling rigs • Incremental optimization of drilling
and completion process has kept cost low without sacrificing EUR
• Extended laterals (XL) improving capital efficiency
Red Fork – Adds Oily Drilling Inventory
NYSE: UNT 12
Red Fork Summary
• 15,100 Net Acres
• 86% HBP
• 64% Average WI
• 30-40 HorizontalLocations
• Well costs:• 4,500’ $6 MM• 9,500’ $7.5 MM
Unit PetroleumSchrock 2215 1HXIP: 2,000Boe/d (51% Oil)
3Unit PetroleumHamar 3H-17IP: 1,000 Boe/d (76% Oil)
2Unit PetroleumFrymire 1-18HIP: 840 Boe/d (8% Oil)
1
Unit Petroleum
Unit PetroleumSchrock 1H-19IP: 290 Boe/d (71% Oil)
4
Red Fork Production Performance
NYSE: UNT 13
Red Fork Type Curve assumes 7,500’ lateral
0
10,000
20,000
30,000
40,000
50,000
60,000
0 50 100 150 200 250 300 350 400 450 500
Cum
ulat
ive
Prod
uctio
n pe
r 1,0
00‘ o
f Lat
eral
(boe
)
Days OnlineSCHROCK 2215 1HX HAMAR #3H-17 FRYMIRE #1-18H SCHROCK 1H-19
STACK Core – Provides High ROR Oil/Wet Gas with Dry Gas Optionality
NYSE: UNT 14
Unit PetroleumContinental ResourcesDevon EnergyCimarexCitizen Energy II
Meramec Horizontal
Denotes Unit Non-Opworking interest
Denotes IP Per Public Data*
Continental ResourcesEagle 1R-15-10XH *IP: 18.0 MMcfe/d 100% Gas
1Continental ResourcesGripe FIU 1-30-31XH *IP: 16.0 MMcfe/d 100% Gas
2Continental ResourcesHeckenberg 2-30-19XHIP: 32.2 MMcfe/d 100% Gas
3MarathonHicks BIA 1-13-12XHIP: 14.8 MMcfe/d 99% Gas
4
Continental ResourcesMol 1-7-8XH *IP: 25.0 MMcfe/d 100% Gas
5
Continental ResourcesLorene 1-8-5XHIP: 5,483 Boe/d 30% Oil
6
MarathonEssinger 1-7MH *IP: 6.8 MMcfe/d 95% Gas
7
Devon EnergyCheetah 32_29-15N-101XHIP: 3,730 Boe/d 41% Oil
8
Devon EnergyTiger Swallowtail 1HXIP: 18.4 MMcfe/d 81% Gas
9
Continental ResourcesPrivott 17_20-16N-9 1HXIP: 4,308 Boe/d 30% Oil
10
1
2
3 4
5
6
7
8
9
10
Type CurveOil
WindowCondensate
WindowDry Gas* Window
IP - 30 (Boe/d, Mcfe/d*) 1,703 1,768 12,224*
ROR (1) 75% 43% 5%
EUR (Mboe/Bcfe*) 1,930 1,961 13.2*
% Liquids/Gas* 65% 58% 99%*
Lateral Length 10,000 10,000 10,000
Well Cost ($mm) $10.7 $10.7 $10.9
STACK Core – Provides High ROR Oil/Wet Gas with Dry Gas Optionality
NYSE: UNT 15
Single Well Economics
1 5/20/2019 Strip Price Deck with 1st Production Starting 4/1/2019. Dry Gas 1stProduction Starting 4/1/2020. See Q2 2019 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
Unit PetroleumContinental ResourcesDevon EnergyCimarexCitizen Energy II
0%
50%
100%
150%
200%
$45 / $2.50 5/20 Nymex $65 / $3.50 $75 / $4.00
IRR
%
Stack Condensate Stack Dry Gas Stack Oil
STACK – Growing into Core Areafor Unit Petroleum
NYSE: UNT 16
Gas NGL Oil
Yearly Net BOE
0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
2016 2017 2018
Geology• Stacked drilling targets in Osage,
Meramec and Woodford• Red Fork Potential in some areas• Sands consistently present across
play
Land• 12,000 net acres in STACK Core• 5,000 net acres in STACK Extension• 85% HBP • 100 - 150 potential operated
locations with working interest of 40 - 60%
• 400 - 800 potential non-operated locations with working interest of ~5%
Operations• Participating ~60 non-op wells
in 2019• Dry gas delayed until gas margins
and takeaway capacity improves
Granite Wash – Low Risk Wet GasCondensate Play with NGL Price Upside
NYSE: UNT 17
Unit Tecolote Jones FourPoint BP LeNorman Granite Wash G Wells
Single Well Economics1 – Granite Wash G
Francis 5713 EXL #3HIP30: 9.5 MMcfe/d (78% Gas)
1
Carr 1357 WXL #4HIP30: 10.0 MMcfe/d (84% Gas)2
Meek 5453 CXL #2HIP30: 3.8 MMcfe/d (80% Gas)
4
Meek 6814 2HFlowing Back @ 7.1 MMcf/d6
1 5/20/2019 Strip Price Deck with 1st Production Starting 4/1/2020See Q2 2019 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)
Francis 5859 EXL 5HIP30: 4.7 Mmcfe/d (73% Gas)5
Meek #6836HIP30: 5.8 MMcfe/d (76% Gas)3
0%
20%
40%
60%
80%
100%
120%
$45 / $2.50 5/20 Nymex $65 / $3.50 $75 / $4.00
IRR
%
Current Pricing Potential After Midship Pipeline
Granite Wash – Competitive AdvantagesDrive Differentiated Value
NYSE: UNT 18
Gas NGL Oil
Buffalo Wallow Yearly Net MMcfe
0
5,000
10,000
15,000
20,000
25,000
2016 2017 2018
Geology• 11 Stacked Granite Wash sands
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%• 100-150 potential XL locations
Operations/Infrastructure/Processing• 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
Wilcox – Conventional Stacked Over-PressuredIntervals Provide Low Cost High Potential
NYSE: UNT 19
JASPER
POLK
3D AREA494 mi.²
HARDIN
Prior Years DrillingHorizontal Wells
TYLER
Gilly Field
0
10
20
30
40
2014 2015 2016 2017 2018Gas Oil NGLs
Wilcox Annual ProductionBCFE
Overall Wilcox Drilling Program Results• Drilled 177 operated wells since 2003
(166 vertical, 11 horizontal)• Program ROR > 80%• Operated with working interest ~ 91%• Production: ~ 92 MMcfe/d (36% liquids)• Running one to two Unit Drilling rig(s)
Gilly Field – Wet Gas Reservoir• 400 Bcfe stacked pay gas resource• Cumulative production ~ 130 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
high potential at low acreage costs
Wilcox Trend Provides an Extensive Play Area
NYSE: UNT 20
Wilcox Strategy for Future Growth
• Continue development of Gilly Field area with vertical and horizontal drilling and stacked pay recompletion/workover opportunities in existing wells
• Drill and delineate high inventory of exploratory prospects (34) (e.g. Wing/Cherry Creek/Brandt prospects)
• Utilize horizontal drilling toextend field boundariesand accelerate reserverecovery
2019 ExplorationHightowerEnterprise
Menard CreekBivens
Shoal Creek
Texas Gulf CoastWilcox Trend
Rig Fleet Presence in Key Regions
NYSE: UNT 21
8
11
24
104
Area # of RigsMid-Continent 11
Bakken 5Niobrara 2Permian 7
Gulf Coast 2Total 27
Current Rigs Operating(1)
• 57 rig fleet • 47% total fleet utilization• 52 rigs pad capable• SCR rigs modified to meet customer
requirements• All 13 BOSS rigs contracted• 14th BOSS rig being constructed
and under long-term contract
(1) As of June 3, 2019.
0
5
10
15
20
25
30
35
40
Dec. 31, 2015 Dec. 31, 2016 Dec. 31, 2017 Dec. 31, 2018 June 3, 2019
A/C SCR
• At industry trough – 13 drilling rigs operating
• Currently, 27 drilling rigs operating
• All BOSS rigs operatingor under contract
• 15 SCR rigs operating
SCR Rigs Continue to Make anImportant Contribution
NYSE: UNT 22
18
12
21
79
10
21
11
15
12
Average Dayrates and Margins (1)
NYSE: UNT 23
(1) See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix.
• Average dayrates increased 2% quarter-over-quarter
• Average utilization has increased from low in Q2 2016.
Average Rig Utilization
Mar
gins
and
Day
rate
s
$0
$5,000
$10,000
$15,000
$20,000
2015 2016 2017 2018 Q1'19
Margins Dayrates Average Rig Utilization
100%
75%
50%
25%
0%
* At the end of 2018, 41 rigs were removed from the fleet.
*
The BOSS Drilling Rig
NYSE: UNT 24
Optimized for Pad Drilling• Multi-direction walking system• Racking & setback capacity for
additional tubulars
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 13 BOSS rigs currently under contract
Long-lead-time components ordered for
14th BOSS rig
Superior Joint Venture Overview
NYSE: UNT 25
• Retains 50% equity interest• Received $300 million• Retains operational control of
Superior
• Acquired 50% equity interest• $300 million consideration• Non-managing member
SP Investor Holdings, LLC50% 50%
Midstream Core Operations
NYSE: UNT 26
TulsaHeadquarters
HemphillCashion
Bellmon
Segno
Processing facilities
Gathering systems
Panola
PittsburghRegional office
Pittsburgh Mills
Brook Field
Snow Shoe
Bruceton Mills
Key Metrics
• 22 active systems
• 12 gas processing plants
• Three natural gas treatmentplants
• 323 MMcf/d processing capacity
• Q1’19 average processing volume of 162 MMcf/d
• Q1’19 average throughput volume of 450 MMcf/d
• Approx. 1,490 miles of pipeline
Appalachia Approx. 71,000 dedicated acres 56 miles of gathering pipeline Connected 7 new wells in Q1’19
East Texas 62 miles of gathering pipeline 120 MMcf/d gathering capacity Q1’19 average gathered volume
of 61.0 MMcf/d
Texas Panhandle Approx. 47,000 dedicated acres 135 MMcf/d processing capacity 331 miles of gathering pipeline
Northern Oklahoma and Kansas Approx. 1,900,000 dedicated acres 176 MMcf/d processing capacity 635 miles of gathering pipeline
Central & Eastern OK Approx. 63,000 dedicated acres 12 MMcf/d processing capacity 404 miles of gathering pipeline
Midstream Segment Contract Mix
NYSE: UNT 27
Contract Mix Based on Margin
Fee BasedCommodity Based
85%28%
72%
15%
Contract Mix Based on Volume
Fee BasedCommodity Based
49%24%
76%51%
2010 Q1 2019
Unit vs. 3rd Party Margin Contribution
3rd PartyUnit
41% 34%66%59%
Debt Structure – No Near-Term Maturities
NYSE: UNT 28
Senior Subordinated Notes
• $650 million, 6.625% coupon
• Maturity of May 15, 2021
• Standard high yield incurrence covenants only, no financial maintenance tests
Unit Secured Credit Facility (Re-determined April 2019) *• Borrowing Base and
• Elected Commitment $425 million• Outstanding(2) $40
• Maturity October 2023
• Key Covenants Current ratio ≥ 1.0 to 1.0(1)Leverage ratio ≤ 4.00(1)
Superior Secured Credit Facility • Elected Commitment $200 million• Outstanding(2) $0
• Maturity May 2023
• Key Covenants Interest coverage ratio > 2.5(1)Leverage ratio < 4.00(1)
* Drilling rigs are not included in borrowing base.
(1) As defined in Indenture/Credit Agreement. (2) As of March 31, 2019.
Ratings S&P Moody’s FitchCorporate B+ B2 B+Senior Subordinated Notes BB- B3 BB-
3/31/2019 3.00x(1,2)
2.12x(1,2)
Segment Contribution
NYSE: UNT 29
Oil and Natural Gas Contract Drilling Midstream
Revenues ($ millions) Adjusted EBITDA ($ millions)(1)
$0
$200
$400
$600
$800
$1,000
2015 2016 2017 2018 Q1'19$0
$100
$200
$300
$400
$500
2015 2016 2017 2018 Q1'19
$843
$190
$854
$602
$740
$84
$407
$250
$313
$371
(1) See Non-GAAP Financial Measures in Appendix.
Chart1
201520152015
201620162016
201720172017
201820182018
Q1'19Q1'19Q1'19
386
266
203
294
122
186
358
175
207
423
196
224
86
51
53
Sheet1
2015201620172018Q1'19
3862943584238645%
2661221751965127%
2031862072245328%
843190
Chart1
201520152015
201620162016
201720172017
201820182018
Q1'19Q1'19Q1'19
263
105
39
180
26
44
223
44
47
260
59
52
54
17
13
Sheet1
2015201620172018Q1'19
2631802232605464%
1052644591720%
394447521315%
40725031437184
Operating Segment Capital Expenditures (1)
NYSE: UNT 30
$0
$100
$200
$300
$400
$500
2015 2016 2017 2018 2019 forecast
Oil and Natural Gas Contract Drilling Midstream
(In Millions)
(1) Net of acquisitions and plugging liability revisions.
$336 MM - $422 MMRange
Investment Highlights
NYSE: UNT 31
• Diversified energy company with upstream, midstream, and drilling rig segments and track record of growing with a capital budget in-line with anticipated cash flow
• Upstream portfolio of high return drilling opportunities, growing oil and liquids component, and attractive full cycle economics
• Midstream assets which enhance UNT’s all-in drilling economics and provide predictable cash flow stream supported by UNT and third party volumes
• High spec A/C rig fleet fully contracted and relevant SCR rig presence
• History of disciplined capital stewardship • Target leverage of
Appendix
NYSE: UNT 32
Non-GAAP Financial Measures - Corporate
NYSE: UNT 33
*Reflects the sale of 50% equity interest of Superior effective 4/1/2018.
Net Income (Loss) $8 ($2) ($1,037) ($136) $118 ($40)Income Taxes 3 (1) (627) (71) (58) (14)Depreciation, Depletion and Amortization 57 62 352 208 209 244Impairments — — 1,635 162 — 148Interest Expense 10 8 32 40 38 34(Gain) loss on derivatives 7 7 (26) 23 (15) 3Settlements during the period of
matured derivative contracts (2) 3 47 10 — (23)
Stock compensation plans 7 5 21 14 18 23Other non-cash items (1) — 3 3 3 (3)(Gain) loss on disposition of assets — 2 7 (3) — (1)Adjusted EBITDA $89 $84 $407 $250 $313 $371Adjusted EBITDA attributable tonon-controlling interest — 7 — — — 21
Adjusted EBITDA attributable to Unit $89 $77 $407 $250 $313 $350
Years ended December 31,2018 2015 2016 2018*(In millions) 2017
Adjusted EBITDA
2019
Three months endedMarch 31,
Non-GAAP Financial Measures - Segments
NYSE: UNT 34
Segment Adjusted EBITDA (with G&A allocated)
(1) After intercompany eliminations.(2) Adjustments per non-GAAP financial measures – corporate schedule (previous slide).Note: Corporate G&A is allocated to the segments based on a weighted average percentage of total segment identifiable assets plus budget segment cap-x, segment depreciation, segment revenues and direct segment G&A minus budgeted divestitures. Superior Pipeline was excluded from the allocation starting in April 2018 since they are directly billed for Corporate G&A per the JV contract and the billed amount is reduced from the Corporate G&A amount allocated to the drilling and oil and gas segments.
Unit PetroleumIncome (Loss) Before Income Taxes (1) $ 26 $ 6 $ (1,622) $ (138) $ 126 $ 139
Depreciation, Depletion and Amortization 31 36 252 114 102 134Impairment of Oil & Natural Gas Properties --- --- 1,599 162 --- ---Other Adjustments (2) 7 12 34 42 (5) (13)
Adjusted EBITDA $ 64 $ 54 $ 263 $ 180 $ 223 $ 260
Unit DrillingIncome (Loss) Before Income Taxes (1) $ (1) $ 5 $ 31 $ (20) $ (15) $ (151)
Depreciation and Impairment 13 13 64 47 56 58Impairment of drilling equipment --- --- --- --- --- 148Other Adjustments (2) 1 (1) 10 (1) 3 4
Adjusted EBITDA $ 13 $ 17 $ 105 $ 26 $ 44 $ 59
Superior PipelineIncome (Loss) Before Income Taxes (1) $ 1 $ 1 $ (33) $ (4) $ 1 $ 8
Depreciation, Amortization and Impairment 11 12 71 46 44 45Other Adjustments (2) --- --- 1 2 2 (1)
Adjusted EBITDA $ 12 $ 13 $ 39 $ 44 $ 47 $ 52
($ In millions)2019 2015 2016 2017
Years ended December 31,20182018
Three months ended March 31,
Contract drilling revenue $45,989 $51,155 $265,668 $122,086 $174,720 $196,492
Contract drilling operating cost 31,667 31,401 156,408 88,154 122,600 131,385
Operating profit from contract drilling $14,322 $19,754 $109,260 $33,932 $52,120 $65,107
Add:
Elimination of intercompany rig profit andbad debt expense 434 1,060 3,991 235 1,620 3,078
Operating profit from contract drilling before elimination of intercompany rig profit andbad debt expense
14,756 20,814 113,251 34,167 53,740 68,185
Contract drilling operating days 2,849 2,822 12,681 6,374 10,964 11,960
Average daily operating margin beforeelimination of intercompany rig profit andbad debt expense
$5,179 $7,376 $8,931 $5,360 $4,901 $5,701
Non-GAAP Financial Measures
NYSE: UNT 35
Reconciliation of Average Contract Drilling Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense
(In thousands except for operating daysand operating margins) 2018 2015 2016 2017 20182019
Years endedDecember 31,
Three months endedMarch 31,
2019 2020Q2 Q3 Q4
Derivative Summary
NYSE: UNT 36
CRUDE:CollarsVolume (Bbl) -- -- -- --Weighted Avg Floor -- -- -- --Weighted Avg Ceiling -- -- -- --3-Way CollarsVolume (Bbl) 364,000 368,000 368,000 --Weighted Avg Floor $61.25 $61.25 $61.25 --Weighted Avg Subfloor $51.25 $51.25 $51.25 --Weighted Avg Ceiling $72.93 $72.93 $72.93 --SwapsVolume (Bbl) -- -- -- --Weighted Avg Swap -- -- -- --
NATURAL GAS:CollarsVolume (MMBtu) 1,820,000 1,840,000 1,840,000 --Weighted Avg Floor $2.63 $2.63 $2.63 --Weighted Avg Ceiling $3.03 $3.03 $3.03 --3-Way CollarsVolume (MMBtu) -- -- -- --Weighted Avg Floor -- -- -- --Weighted Avg Subfloor -- -- -- --Weighted Avg Ceiling -- -- -- --SwapsVolume (MMBtu) 5,460,000 5,520,000 4,300,000 --Weighted Avg Swap $2.90 $2.90 $2.90 --Basis SwapsVolume (MMBtu) 5,460,000 5,520,000 5,520,000 10,980,000Weighted Avg Swap ($0.46) ($0.46) ($0.46) ($0.28)
CrudeNatural
GasPEPL Basis
NGPL-Midcon
Basis MB C2 MB C3
MB C3 $ per
barrel MB NC4 MB iC4 MB C5+ CW C2 CW C3 CW NC4 CW iC4 CW C5+
2019 $63.170 $2.732 ($0.525) ($0.530) $0.237 $0.575 $24.154 $0.595 $0.605 $1.283 $0.105 $0.510 $0.513 $0.550 $1.195
2020 $60.383 $2.750 ($0.440) ($0.410) $0.238 $0.550 $23.088 $0.569 $0.578 $1.226 $0.106 $0.488 $0.490 $0.526 $1.142
2021 $56.764 $2.666 ($0.410) ($0.380) $0.231 $0.517 $21.704 $0.535 $0.544 $1.153 $0.102 $0.458 $0.461 $0.494 $1.074
2022 $54.602 $2.658 ($0.410) ($0.380) $0.230 $0.497 $20.878 $0.514 $0.523 $1.109 $0.102 $0.441 $0.443 $0.475 $1.033
Thereafter $54.602 $2.658 ($0.410) ($0.380) $0.230 $0.497 $20.878 $0.514 $0.523 $1.109 $0.102 $0.441 $0.443 $0.475 $1.033
Q2 2019 Economic Prices
NYSE: UNT 37
Strip Case*
*Strip prices as of 5/20/2019.
Bank of America Merrill Lynch Energy Credit Conference�June 5, 2019Forward Looking StatementA Diversified Energy CompanyInvestment HighlightsCore Upstream Producing AreasReserve DetailTrack Record of Reserve GrowthCore Area Cash MarginsSOHOT – Low Cost, High ROR Oil PlaySOHOT – Low Cost, High ROR Oil PlaySOHOT – Growing Oil Production� and Improving Capital EfficiencyRed Fork – Adds Oily Drilling InventoryRed Fork Production PerformanceSTACK Core – Provides High ROR Oil/Wet Gas with Dry Gas OptionalitySTACK Core – Provides High ROR Oil/Wet Gas with Dry Gas OptionalitySTACK – Growing into Core Area� for Unit PetroleumGranite Wash – Low Risk Wet Gas� Condensate Play with NGL Price UpsideGranite Wash – Competitive Advantages� Drive Differentiated ValueWilcox – Conventional Stacked Over-Pressured� Intervals Provide Low Cost High PotentialWilcox Trend Provides an Extensive Play AreaRig Fleet Presence in Key RegionsSCR Rigs Continue to Make an� Important ContributionAverage Dayrates and Margins (1)The BOSS Drilling RigSuperior Joint Venture OverviewMidstream Core OperationsMidstream Segment Contract MixDebt Structure – No Near-Term MaturitiesSegment ContributionOperating Segment Capital Expenditures (1)Investment HighlightsAppendixNon-GAAP Financial Measures - CorporateNon-GAAP Financial Measures - SegmentsNon-GAAP Financial MeasuresDerivative SummaryQ2 2019 Economic Prices