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