Johnson Rice conference 2018 - A Diversified Energy CompanyJohnson Rice Energy Conference September 25, 2018 2 Forward Looking Statement This presentation contains forward-looking

Johnson Rice Energy Conference

September 25, 2018

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

15

Casper Casper

Arkoma Basin

Marcellus

North La/ East Texas Basin

Gulf Coast Basin

Anadarko Basin

Permian Basin

96 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%29%

17%

Q2 2018 Daily Production: 46.3 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%

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% 35% 42% 60% 63% 99%

$7.08

$5.05

$4.09

$2.71 $2.32

$1.27

$1.56

$1.17

$1.18

$1.13 $1.13

$0.92

$0.41

$0.62

$0.71

$0.74 $1.30

$0.80

Adjusted Base$9.05

Adjusted Base$6.85

Adjusted Base$5.98

Adjusted Base$4.58

Adjusted Base$4.75

Adjusted Base$2.98

Gas Base, $2.81

$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

Differential - Adjusted*

LOE & Taxes

Cash Margin

*Differentials adjusted for production stream mix

Core Area Cash Margins

Type CurveMarchand

5,000’Marchand

7,500’

IP - 30 (Boe/d) 668 935

ROR 122% 173%

EUR (Mboe) 525 737

% Liquids 82% 82%

Lateral Length 5,000 7,500

Well Cost ($mm) $5.4 $6.7

8

1

LeaseSpudDate

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 7,825Schenk Tr. #2-17HXL* Unit 4/18 1,625 80 7,047Schenk Tr. #3-17HXL* Unit 5/18 1,669 75 7,777Liv. 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

Denotes Unit non-op working interest.

Single Well Economics

Operator

SOHOT – Low Cost, High ROR Oil Play

2

6

7

5

3

4

1 8/1/2018 Strip Price Deck with 1st Production Starting 10/1/2018.See Q3 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)

*Denotes Well online less than 30 days

8

9

1

2

3

5

4

6

7

9

8

0%

50%

100%

150%

200%

250%

300%

350%

$60 / $2.50 8/1 Nymex $70 / $3.00 $80 / $3.50

IRR

%

Marchand 5k Marchand 7.5k

9

Geology• Marchand stacked lenses provide

multiple oil drilling targets• Medrano proved gas potential

Land• 23,000 contiguous net acres• 84% HBP• Majority operated• Average working interest 86%• 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 Q2'18

Gas NGL Oil Production Delayed Dueto Pipeline Event

Type CurveOil

WindowCondensate

WindowDry Gas* Window

IP - 30 (Boe/d, Mcfe/d*) 1,693 1,756 14,023*

ROR 111% 71% 4%

EUR (Mboe/Bcfe*) 1,925 1,941 15.4*

% Liquids/Gas* 63% 55% 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% 9,743Mol* Continental 8/2017 25.0 100% 9,469Hicks BIA Marathon 7/2017 14.8 99% 9,652Essinger* Marathon 10/2017 6.8 95% 4,618Wyatt* Continental 8/2016 16.5 100% 8,805Eagle* Continental 9/2017 18.0 100% 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 9/2017 1,734 57% 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* Citizen II 7/2017 1,475 27% 8,423

10


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

1

2

3

4

6

9

OilCondensate

Dry Gas

Unit’s AcreageMeramec Woodford

1

3

2

4

5

9

10

11

12

13

14

15

Denotes Unit working interest

15


7

8

7

8

3 5

5

*Denotes IP Per Public Data (>30 days)

0%

50%

100%

150%

200%

250%

$60 / $2.50 8/1 Nymex $70 / $3.00 $80 / $3.50

IRR

%

Stack Condensate Stack Dry Gas Stack Oil

10

11

12

13

14

Type CurveSTACK ExtMeramec

STACKOsage

IP - 30 (Boe/d) 1,199 1,160

ROR 96% 33%

Total EUR (Mboe) 1,064 996

% Liquids 57% 53%

Lateral Length 5,000 5,000

Well Cost ($mm) $6.2 $7.3

11

Lease Operator Spud DateIP-30Boe/d

Liquids %

Lateral Length

Cox Tapstone 9/2017 1,583 20% 10,009Rebecca Tapstone 11/2017 788 50% 10,130GTO Judge Devon 12/2017 1,117 35% 9,431Bond 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

Irwin* Unit 5/2018 5.7 90% 4,567Tucker 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 AcreageMeramec Osage

1

2

3

4

5

6

7

8

9

10

1

2

34

5

6

7

89


STACK West – Successful Extension of Meramec and Potential for Osage Development

11

12

12

11

10

14


13

*Denotes Well online less than 30 days

0%

50%

100%

150%

200%

250%

$60 / $2.50 8/1 Nymex $70 / $3.00 $80 / $3.50

IRR

%

Stack Ext Meramec Stack Osage

13

14

12

STACK – Growing into Core Areafor Unit Petroleum

Gas NGL Oil

Quarterly Net BOEGeology• 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/STACK West• 85% HBP • 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 Q1'18

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’

Meek 6814 XL #1H Unit 3/18 5.5 49% 9,410’

13

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 7,900ROR 47% 49% 29%EUR (Bcfe) 7.6 14.2 7.1% Gas 48% 77% 52%Lateral Length 7,500 7,500 7,500Well Cost ($mm) $6.2 $6.2 $6.2

GW C1


Unit Tecolote Jones FourPoint Le Norman BPGW B

1

GW G

2

3

4

5

6

7

1 23 4

5

6

7

Operator


88

0%

20%

40%

60%

80%

100%

120%

$60 / $2.50 8/2 Nymex $70 / $3.00 $80 / $3.50

IRR %

Granite Wash C1 Granite Wash G Granite Wash B

14

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%• 100-150 potential XL locations

Operations/Infrastructure/Processing• Running two Unit Drilling rigs• 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

4,500

5,000

Q1'17 Q2'17 Q3'17 Q4'17 Q1'18 Q2'18

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 ~ 125 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 costs

Wilcox Annual ProductionBCFE

0.40

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 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 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 (e.g. Gilly/NE Segno/Village Mills Fields)

17

Rig Fleet Presence in Key Regions

10

10

55

156

Area # of RigsMid‐Continent 19

Bakken 5Niobrara 1Permian 7

DJ 1Gulf Coast 1

Total 34

Current Rigs Operating(1)

96 rig fleet

70% electric 54% 1,500 HP or greater 35 equipped with skidding or walking systems 27 additional can be skidded

35% total fleet utilization at present All eleven BOSS rigs operating Entered into long-term contracts for

12th and 13th BOSS rigs

20 ≤800 HP: 21%72 1,000-1,700 HP: 75%

4 ≥2,000 HP: 4%

(1) As of September 21, 2018.

18

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 Sep. 21, 2018

A/C SCR

• At industry trough – 13 drilling rigs operating

• Currently, 34 drilling rigs operating

• All BOSS rigs operating

• 23 SCR rigs operating7

12

26

21

6

910 10

23

11

19

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 Q2'18

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

20

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 11 BOSS rigs currently under contract

12th and 13th BOSS rig sunder contract (components

being assembled)

21

• 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

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%

22

Midstream Core Operations

Appalachia 70,894 dedicated acres 53 miles of gathering pipeline Q2’18 average gathered volume

of 123.3 MMcf/d Connected 7 new infill wells in

Q2 ‘18

TulsaHeadquarters

Hemphill

Reno

Bellmon

Segno

Processing facilities

Gathering systems

Panola

Key Metrics

• 22 active systems

• Three natural gas treatmentplants

• 348 MMcf/d processing capacity

• Q2’18 average processing volume of 161 MMcf/d

• Approx. 1,457 miles of pipeline

East Texas 62 miles of gathering

pipeline 120 MMcf/d dehy capacity Q2’18 average gathered

volume of 84.1 MMcf/d

Texas Panhandle 46,900 dedicated acres 135 MMcf/d processing capacity 331 miles of gathering pipeline

Northern Oklahoma and Kansas 1,752,102 dedicated acres 201 MMcf/d processing capacity 614 miles of gathering pipeline

Central & Eastern OK 62,720 dedicated acres 12 MMcf/d processing capacity 397 miles of gathering pipeline

PittsburghRegional office

Pittsburgh Mills

Brook Field

Snow Shoe

Bruceton Mills

23

Midstream Segment Contract Mix

Contract Mix Based on Margin

Fee BasedCommodity Based

85%40%

60%

15%

Contract Mix Based on Volume

Fee BasedCommodity Based

49%34%

66%51%

2010 Q2 ‘2018

Unit vs. 3rd Party Margin Contribution

3rd PartyUnit

41% 39%61%59%

24

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 $425 million

Outstanding(2) $0

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 June 30, 2018.

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

6/30/20186.28x(1,2)

6/30/2018 3.67x(1,2)

0x(1,2)

25

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 6 mos. '18$0

$200

$400

$600

$800

2014 2015 2016 2017 6 mos. '18

$408

$1,573

$854

$602

$740

$785

$408

$250

$313

$178

(1) See Non-GAAP Financial Measures in Appendix (also available at www.unitcorp.com/investor/reports.html).

26

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.

27

APPENDIX

28

Non-GAAP Financial Measures - Corporate

Adjusted EBITDA

Years endedDecember 31,

($ In Millions) 2018 2014 2015 2016 2017

Net Income (Loss) $25 $16 $136 ($1,037) ($136) $118Income Taxes 20 6 87 (627) (71) (58)Depreciation, Depletion and Amortization

97 115 403 353 208 209

Impairments --- --- 158 1,635 162 ---Interest Expense 19 18 17 32 40 38 (Gain) loss on derivatives (24) 21 (30) (26) 23 (15)Settlements during the period of matured derivative contracts

(2) (9) (6) 47 10 ---

Stock compensation plans 8 12 24 21 14 18 Other non-cash items 2 (1) 5 3 3 3 (Gain) loss on disposition of assets (1) --- (9) 7 (3) ---Adjusted EBITDA $144 $178 $785 $408 $250 $313 Adjusted EBITDA attributable to non-controlling interest

--- 7 --- --- --- ---

Adjusted EBITDA attributable to Unit $144 $171 $785 $408 $250 $313

2017

Six months endedJune 30,

29

Non-GAAP Financial Measures - Segments

Segment Adjusted EBITDA (with G&A allocated)

(1) After intercompany eliminations.(2) Adjustments per non-GAAP financial measures – corporate schedule (previous slide).

Unit PetroleumIncome (Loss) Before Income Taxes (1) $ 64 $ 75 $ 199 $ (1,631) $ (102) $ 125

Depreciation, Depletion and Amortization 45 62 276 252 114 102Impairment of Oil and Natural Gas Properties --- --- 77 1,599 162 ---Other Adjustments (2) (4) (14) (10) 43 6 (5)

Adjusted EBITDA $ 105 $ 123 $ 542 $ 263 $ 180 $ 222

Unit DrillingIncome (Loss) Before Income Taxes (1) $ (7) $ 2 $ 42 $ 45 $ (13) $ (4)

Depreciation and Impairment 27 27 160 64 47 56Other Adjustments (2) (4) (3) (6) (4) (8) (8)

Adjusted EBITDA $ 16 $ 26 $ 196 $ 105 $ 26 $ 44

Superior PipelineIncome (Loss) Before Income Taxes (1) $ 4 $ 7 $ 2 $ (30) $ 2 $ 8

Depreciation, Amortization and Impairment 22 22 48 71 46 44Other Adjustments (2) (3) --- (3) (2) (4) (5)

Adjusted EBITDA $ 23 $ 29 $ 47 $ 39 $ 44 $ 47

($ In Millions) 2018 2014 2015 2016 20172017



30

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 $76,440 $92,915 $476,517 $265,668 $122,086 $174,720

Contract drilling operating cost 56,466 63,561 274,933 156,408 88,154 122,600

Operating profit from contract drilling $19,974 $29,354 $201,584 $109,260 $33,932 $52,120

Add:

Elimination of intercompany rig profit and bad debt expense

376 1,248 29,343 3,991 235 1,620

Operating profit from contract drilling before elimination of intercompany rig profit and bad debt expense

20,350 30,602 230,927 113,251 34,167 53,740

Contract drilling operating days 4,916 5,778 27,516 12,681 6,374 10,964

Average daily operating margin beforeelimination of intercompany rig profit and bad debt expense

$4,139 $5,296 $8,392 $8,931 $5,360 $4,901

2018



31

Derivative Summary

2018 2019 2020Q3 Q4

CRUDE:CollarsVolume (Bbl) -- -- -- --Weighted Avg Floor -- -- -- --Weighted Avg Ceiling -- -- -- --3-Way CollarsVolume (Bbl) 184,000 184,000 1,460,000 --Weighted Avg Floor $47.50 $47.50 $61.25 --Weighted Avg Subfloor $37.50 $37.50 $51.25 --Weighted Avg Ceiling $56.08 $56.08 $72.93 --SwapsVolume (Bbl) 368,000 368,000 -- --Weighted Avg Swap $53.52 $53.52 -- --

NATURAL GAS:CollarsVolume (MMBtu) 2,760,000 -- -- --Weighted Avg Floor $2.67 -- -- --Weighted Avg Ceiling $2.97 -- -- --3-Way CollarsVolume (MMBtu) 1,840,000 1,840,000 -- --Weighted Avg Floor $3.00 $3.00 -- --Weighted Avg Subfloor $2.50 $2.50 -- --Weighted Avg Ceiling $3.51 $3.51 -- --SwapsVolume (MMBtu) 3,680,000 2,150,000 3,650,000 --Weighted Avg Swap $2.99 $3.01 $2.81 --Basis SwapsVolume (MMBtu) 2,760,000 2,450,000 21,900,000 10,950,000Weighted Avg Swap ($0.48) ($0.52) ($0.46) ($0.28)

PROPANE:SwapsVolume (Bbl) 138,000 -- -- --Weighted Avg Swap $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 $66.525 $2.812 $0.375 $0.924 $38.818 $1.077 $1.091 $1.475 $0.127 $0.693 $0.809 $0.978 $1.228

2019 $63.563 $2.710 $0.361 $0.883 $37.089 $1.029 $1.043 $1.409 $0.123 $0.662 $0.773 $0.935 $1.173

2020 $60.526 $2.600 $0.346 $0.841 $35.317 $0.980 $0.993 $1.342 $0.118 $0.631 $0.736 $0.890 $1.117

2021 $57.988 $2.567 $0.342 $0.806 $33.837 $0.938 $0.951 $1.286 $0.116 $0.604 $0.705 $0.853 $1.070

2022 $56.145 $2.600 $0.346 $0.780 $32.761 $0.909 $0.921 $1.245 $0.118 $0.585 $0.683 $0.826 $1.036

Thereafter $56.145 $2.600 $0.346 $0.780 $32.761 $0.909 $0.921 $1.245 $0.118 $0.585 $0.683 $0.826 $1.036

32

Q3 2018 Economic Prices

Strip Case*

*Strip prices as of 8/2/2018.

JOHNSON RICE ENERGY CONFERENCE

September 25, 2018

Documents

Johnson Rice conference 2018 - A Diversified Energy CompanyJohnson Rice Energy Conference September 25, 2018 2 Forward Looking Statement This presentation contains forward-looking