EnerCom’s Dallas Oil & Gas ConferenceFebruary 27, 2019

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 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.

3

A Diversified Energy Company

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

4

Investment Highlights

§ 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 substantial relevant SCR rig presence

§ History of excellent capital stewardship § Target leverage of <2.0x adjusted EBITDA at mid-cycle

commodity prices

5

Core Upstream Producing Areas

GasNGLs

Oil

54%29%

17%

2018 Daily Production: 46.8 MBoe/d

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)

0

10

20

30

40

50

60

2014 2015 2016 2017 2018 2019 estNatural Gas Oil / NGLs

48-49474750 55

44

Average Production (MBoe/d)Net Wells Drilled:

121 35 10 26 33 30-40

6

Reserve Detail

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%

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

7

Natural Gas Oil / NGLs

Track Record of Reserve Growth

-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 Reserve Replacement

161%171% 176%202% 204%

261%221%

186%

Average: 176%

113%

116

160

6979 86

95 96104

150

337%

179Proved Reserves (MMBoe)

135118

150

58484542

285%

166%169%161%

(1%)

300%

160

158%

8

Unit PetroleumMcConnell 1-11HIP: 1,271 Boe/d 63% Oil

3

Kaiser FrancisAmanda 21-6-8 1HIP: 540 Boe/d 71% Oil

10

Kaiser FrancisTorralba 10-5-8 1HIP: 578 Boe/d 70% Oil

9

Unit Petroleum5D 13/12 1HXLIP: 520 Boe/d 88% Oil

8

Unit PetroleumLivingston Land 1HXLIP: 565 Boe/d 72% Oil

7

Unit PetroleumSchenk Trust 3-17HXLIP: 1,470 Boe/d 75% Oil

6

Unit PetroleumSchenk Trust 1-17HXLIP: 2,349 Boe/d 79% Oil

4Unit PetroleumNina 1-22HIP: 1,124 Boe/d 76% Oil

2

Unit PetroleumCaminoEcho E&P LLCKaiser- FrancisLimerock Resources

Unit PetroleumSchmidt 1-10HIP: 687 Boe/d 80% Oil

1

Denotes Unit Non-Op working interest Marchand Horizontal

SOHOT – Low Cost, High ROR Oil Play

Unit PetroleumSchenk Trust 2-17HXLIP: 1,463 Boe/d 79% Oil

5

9

Single Well Economics

SOHOT – Low Cost, High ROR Oil Play

1 2/1/2019 Strip Price Deck with 1st Production Starting 4/1/2019.See Q1 2019 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)

Unit PetroleumCaminoEcho E&P LLCKaiser- FrancisLimerock Resources

Type CurveMarchand

5,000’Marchand

7,500’

IP - 30 (Boe/d) 699 978

ROR (1) 81% 115%

EUR (Mboe) 620 883

% Liquids 77% 77%

Lateral Length 5,000 7,500

Well Cost ($mm) $5.3 $6.6

0%

50%

100%

150%

200%

250%

300%

350%

$45 / $2.50 2/1 Nymex $65 / $3.50 $75 / $4.00

IRR

%

5,000' Lateral 7,500' Lateral

Marchand Horizontal

10

Unit PetroleumSchrock 2215 1HXIP: 2,000Boe/d (80% Oil)

3

Unit Petroleum

Red Fork – Adds Oily Drilling Inventory

Red Fork Summary

• 10,600 Net Acres

• 86% HBP

• 64% Average WI

• 20-30 Horizontal Locations

• Well costs:• 4,500’ $6 MM• 9,500’ $7.5 MM

Unit PetroleumHamar 3H-17IP: 1,000 Boe/d (76% Oil)

2Unit PetroleumFrymire 1-18HIP: 840 Boe/d (8% Oil)

1

11

STACK Core - Provides High ROR Oil/Wet Gas with Dry Gas Optionality

1

2

Continental ResourcesHeckenberg 2-30-19XHIP: 32.2 MMcfe/d 100% Gas

3

3

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

Devon EnergyCheetah 32_29-15N-101XHIP: 3,730 Boe/d 41% Oil

8

MarathonEssinger 1-7MH *IP: 6.8 MMcfe/d 95% Gas

7

Continental ResourcesLorene 1-8-5XHIP: 5,483 Boe/d 30% Oil

6

Continental ResourcesMol 1-7-8XH *IP: 25.0 MMcfe/d 100% Gas

5

MarathonHicks BIA 1-13-12XHIP: 14.8 MMcfe/d 99% Gas

4Continental ResourcesGripe FIU 1-30-31XH *IP: 16.0 MMcfe/d 100% Gas

2Unit PetroleumContinental ResourcesDevon EnergyCimarexCitizen Energy II

Continental ResourcesEagle 1R-15-10XH *IP: 18.0 MMcfe/d 100% Gas

1

4

5

*Denotes IP Per Public Data Denotes Unit working interest

6

7

8

9

10

Meramec Horizontal

0%

20%

40%

60%

80%

100%

120%

140%

$45 / $2.50 2/1 Nymex $65 / $3.50 $75 / $4.00

Current Price Structure Potential After Midship Pipeline

12

Granite Wash – Low Risk Wet Gas Condensate Play with NGL Price Upside

Single Well Economics – Granite Wash G

Granite Wash G WellsUnit Tecolote Jones FourPoint BP

1 2/01/2019 Strip Price Deck with 1st Production Starting 4/1/2019.See Q1 2019 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)

Francis 5713 EXL #3HIP30: 9.5 Mmcfe/d (78% Gas)1

Carr 1357 WXL #4HSpot: 9.5 Mmcfe/d (84% Gas)2

Meek #6836HSpot: 5.7 Mmcfe/d (76% Gas)3

Meek 5453 CXL #2HBeing Completed4

IRR%

(1)

Wilcox Trend Provides an Extensive Play Area

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) with homerun potential (e.g. Wing/ Cherry Creek/Brandt prospects)

§ Utilize horizontal drilling to extend field boundaries and accelerate reserve recovery

2019 ExplorationHightowerEnterpriseMenard CreekBivensShoal Creek

14

Rig Fleet Presence in Key Regions

8

11

24

104

Area # of RigsMid-Continent 17

Bakken 5Niobrara 2Permian 7

Gulf Coast 1Total 32

Current Rigs Operating(1)

§ 57 rig fleet § 56% total fleet utilization§ 52 rigs pad capable§ SCR rigs modified to meet customer

requirements§ All 13 BOSS rigs operating§ 12th and 13th BOSS rigs completed and

placed into service – Q1 ‘19

(1) As of February 21, 2019.

0

5

10

15

20

25

30

35

40

Dec. 31, 2015 Dec. 31, 2016 Dec. 31, 2017 Dec. 31, 2018 Feb. 21, 2019

A/C SCR

15

SCR Rigs Continue to Make anImportant Contribution

• At industry trough – 13 drilling rigs operating

• Currently, 32 drilling rigs operating

• All BOSS rigs operating

• 19 SCR rigs operating

18

12

21

79

10

21

11

19

13

16

Average Dayrates and Margins (1)

Average Rig Utilization

Mar

gins

and

Day

rate

s

$0

$5,000

$10,000

$15,000

$20,000

2014 2015 2016 2017 2018

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.

• Decline in dayrates lagged utilization decrease due to long-term contract roll-off

• Utilization increased from low in Q2 2016

17

The BOSS Drilling Rig

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 availablewith 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

18

• Retains 50% equity interest• Received $300 million• Retains operational control of

Superior

Superior Joint Venture Overview

• Acquired 50% equity interest• $300 million consideration• Non-managing member

Superior Credit Facility:On May 10, 2018, Superior entered into a five year $200 million senior secured revolving credit facility with an option to increase the credit amount up to $250 million, subject to certain conditions.

SP Investor Holdings, LLC50% 50%

19

Midstream Core Operations

Appalachia§ Approx. 71,000 dedicated acres§ 56 miles of gathering pipeline§ Connected 7 infill wells in 2018§ Connected a new 7-well pad in

Q1 2019

TulsaHeadquarters

HemphillCashion

Bellmon

Segno

Processing facilities

Gathering systems

Panola

Key Metrics

• 22 active systems

• 14 gas processing plants

• Three natural gas treatmentplants

• 348 MMcf/d processing capacity

• Q4’18 average processing volume of 161 MMcf/d

• 2018 average throughput volume of 394 MMcf/d

• Approx. 1,474 miles of pipeline

East Texas§ 62 miles of gathering pipeline§ 120 MMcf/d gathering capacity§ Q4’18 average gathered volume

of 73.1 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§ 201 MMcf/d processing capacity§ 624 miles of gathering pipeline

Central & Eastern OK§ Approx. 63,000 dedicated acres§ 12 MMcf/d processing capacity§ 397 miles of gathering pipeline

PittsburghRegional office

Pittsburgh Mills

Brook Field

Snow Shoe

Bruceton Mills

20

Midstream Segment Contract Mix

Contract Mix Based on Margin

Fee BasedCommodity Based

85%39%

61%

15%

Contract Mix Based on Volume

Fee BasedCommodity Based

49%33%

67%51%

2010 2018

Unit vs. 3rd Party Margin Contribution

3rd PartyUnit

41% 39%61%59%

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 October 2018) *§ Borrowing Base and

Elected Commitment $425 million

§ Outstanding(2) $0

§ 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)

21

Debt Structure – No Near-Term Maturities

* Drilling rigs are not included in borrowing base.

(1) As defined in Indenture/Credit Agreement. (2) As of December 31, 2018.

Ratings S&P Moody’s FitchCorporate B+ B2 B+Senior Subordinated Notes BB- B3 BB-

12/31/2018 3.18x(1,2)

2.02x(1,2)

22

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 2018

$0

$200

$400

$600

$800

2014 2015 2016 2017 2018

$843

$1,573

$854

$602

$740

$785

$407

$250

$313

$371

(1) See Non-GAAP Financial Measures in Appendix.

23

Operating Segment Capital Expenditures (1)

$0

$500

$1,000

$1,500

2014 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

24

Investment Highlights

§ 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 substantial relevant SCR rig presence

§ History of excellent capital stewardship § Target leverage of <2.0x adjusted EBITDA at mid-cycle

commodity prices