IPAA Oil & Gas Investment Symposium - Unit Corporation - A … · · 2018-04-10• Retains 50% equity interest • Received $300 million • Retains operational control of Superior

Bank of America Merrill LynchEnergy Credit Conference

June 6, 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

14

Casper Casper

Arkoma Basin

Marcellus

North La/ East Texas Basin

Gulf Coast Basin

Anadarko Basin

Permian Basin

95 Unit Rigs

E&P Operations

Midstream Operations

Office Location

• Tulsa based, incorporated in 1963

• Integrated approach to business allows Unit to capture margin from each business segment

Houston Houston

Oklahoma City

Oklahoma City

Tulsa HeadquartersTulsa Headquarters

PittsburghPittsburghMississippianBasin

4

Investment Highlights

• Opportunity-rich upstream portfolio with compelling economics provides optionality

• Upstream capital allocated to areas generating highest rates of return in the Company’s portfolio

• Contract drilling segment activity level rebounding• Sale of 50% equity stake in Superior highlights asset value

and provides growth capital to benefit all three Unit Business segments

• Conservative balance sheet with corporate net debt < 2X EBITDA and philosophy of spending within cash flow

5

Core Upstream Producing Areas

GasNGLs

Oil

54%28%

18%

Q1 2018 Daily Production: 46.5 MBoe/d

Mid Continent Region

Upper Gulf Coast Region

Wilcox

Hoxbar/STACK

Granite Wash

Key focus areas include:Gulf Coast: Wilcox (Southeast Texas)

Mid-Continent: Granite Wash (Texas Panhandle) Hoxbar (Western Oklahoma) STACK (Western Oklahoma)

0

10

20

30

40

50

60

2013 2014 2015 2016 2017 2018 est

Natural Gas Oil / NGLs

47-4846 475055

44

Average Production (MBoe/d)Net Wells Drilled:

91 121 35 10 26 ~34

6

Natural Gas Oil / NGLs

Track Record of Reserve Growth

-150%

0%

150%

300%

450%

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

(119%)

0

30

60

90

120

150

180

20

01

20

02

20

03

20

04

20

05

20

06

20

07

20

08

20

09

20

10

20

11

20

12

20

13

20

14

20

15

20

16

20

17

Annual Reserve Replacement

161%171% 176%202% 204%

261%221%

186%

Average: 176%

113%

116

160

6979

8695 96 104

150

337%

179Proved Reserves (MMBoe)

135118

150

58484542

285%

166%169%161%

(1%)

300%

7

Core Area Cash Margins

Note: Assumes 6:1 gas to oil ratio. Adjusted base represents the weighted average commodity price per Mcfe of the area’s production (using WTI, Henry Hub and Mont Belvieu propane for NGL). Adjusted Base also includes 50% of applicable midstream margin for Granite Wash and Wilcox.

% Gas 17% 25% 42% 60% 63% 99%

$7.03

$4.88

$3.87

$2.93 $2.21

$1.33

$1.56

$1.17

$1.18

$0.97

$1.09

$0.88

$0.42

$0.70

$0.81

$0.87 $1.29

$0.80

Adjusted Base$9.01

Adjusted Base$6.75

Adjusted Base$5.86

Adjusted Base$4.76 Adjusted Base

$4.59

Adjusted Base$3.01

Gas Base, $2.85

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

$10.00

SOHOT STACK Oil STACKCondensate

Wilcox Granite Wash STACK Dry Gas

$/M

cfe

Differential - Adjusted

LOE & Taxes

Cash Margin

*Differentials adjusted forproduction stream mix

*

Type CurveMarchand

5,000’Marchand

7,500’

IP - 30 (Boe/d) 667 933

ROR 119% 171%

EUR (Mboe) 524 737

% Liquids 83% 83%

Lateral Length 5,000’ 7,500’

Well Cost ($mm) $5.4 $6.7

8

1Lease

SpudDate

IP-30Boe/d % Oil

LateralLength

Schmidt #1-10H Unit 9/17 687 80 5,000Nina #1-22H Unit 8/17 1,124 76 4,855McConnell #1-11H Unit 10/17 1,091 63 4,943Schenk Tr. #1-17HXL Unit 11/17 2,343 79 7,825Liv. Land #1HXL Unit 1/18 499 72 7,985Torralba 10-5-8 #1H Kaiser 1/17 575 70 4,839Amanda 21-6-8 #1H Kaiser 3/17 540 71 5,050

1

2

3

5

Marchand VerticalMarchand Horizontal

4

Denotes Unit non-op working interest. 6

7

0%

50%

100%

150%

200%

250%

300%

350%

$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50

IRR

%

Marchand 5k Marchand 7.5k

Single Well Economics

Operator

SOHOT – Low Cost, High ROR Oil Play

2

6

7

5

3

4

1 5/1/2018 Strip Price Deck with 1st Production Starting 5/1/2018.See Q2 2018 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports/html)

9

Geology• Marchand stacked lenses provide

multiple oil drilling targets• Medrano proved gas potential

Land• 23,000 contiguous net acres• 65% HBP• Majority operated• Working interest 50-70%• 40 to 50 location inventory steady with

continued acquisition of bolt on acreage• Waterflood potential

Operations• Running one Unit Drilling rig • Incremental optimization of drilling and

completion process has kept cost low without sacrificing EUR

• Extended laterals (XL) improving capital efficiency

SOHOT – Growing Oil Production and Improving Capital Efficiency

Quarterly Net BOE

0

100,000

200,000

300,000

400,000

500,000

600,000

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

Gas NGL Oil

WellSpudDate

IP-30MMcfe/d

Gas%

LateralLength

Dixon 5554 XL #1H Unit 2/16 12.5 47% 7,503’

Dixon 5554 EXL #4H Unit 2/17 7.5 47% 7,474’

Carr 1357 EXL #1H Unit 3/17 14.9 45% 7,891’

Carr 1357 EXL #2H Unit 5/17 9.2 45% 7,663’

Francis 5859 EXL #2H Unit 9/17 8.1 49% 9,442’

Dixon 5554 EXL #5H Unit 6/17 2.1 64% 7,802’

Meek 6836H Unit 5/14 5.7 61% 4,375’

10

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

Type CurveGranite

Wash C1Granite Wash G

Granite Wash B

IP - 30 (Mcfe/d) 9,960 9,000 7,902ROR 43% 44% 26%EUR (Bcfe) 7.6 14.2 7.1% Gas 48% 77% 52%Lateral Length 7,500’ 7,500’ 7,500’Well Cost ($mm) $6.2 $6.2 $6.2

GW C1


Unit Tecolote Jones FourPoint Le Norman BPGW B

1

GW G

2

3

4

5

6

7

1 23 4

5

6

7

0%

20%

40%

60%

80%

100%

120%

$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50

IRR %

Granite Wash C1 Granite Wash G Granite Wash B

Operator


11

Granite Wash – Competitive Advantages Drive Differentiated Value

Gas NGL Oil

Geology• 11 Stacked Granite Wash lenses

significantly improves capital efficiency• Sands present across acreage

Land• 9,000 net largely contiguous acres allow

for extended lateral (XL) drilling• 90% HBP and Operated• Average working interest 90%• 150-200 potential XL locations• Continuing to expand position

Operations/Infrastructure/Processing• Running one Unit Drilling rig• Incremental process improvements

continue to decrease drilling days• SWD network lowers disposal costs 80%• Water recycling pits lower frack costs• Electricity across field lowers lifting costs• Superior processes the gas improving

cash margin

Buffalo Wallow Quarterly Net MMcfe

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

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

Type CurveOil

WindowCondensate

WindowDry Gas* Window

IP - 30 (Boe/d, Mcfe/d*) 1,706 1,773 15,415*

ROR 108% 68% 15%

EUR (Mboe/Bcfe*) 1,939 1,958 18.9*

% Liquids/Gas 65% 58% 99%

Lateral Length 10,000’ 10,000’ 10,000’

Well Cost ($mm) $10.7 $10.7 $10.9

Lease Operator Spud DateIP-30

MMcfe/dGas %

Lateral Length

Anderson Half Continental 2/2016 17.1 99% 9,676Edith Mae Continental 6/2016 23.6 99% 9,743Abbott Com Cimarex 8/2017 Flowing Back 10,385Hicks BIA Marathon 7/2017 14.8 99% 9,652Reece Jane Continental 2/2017 16.6 100% 9,898Wyatt Continental 8/2016 16.5 100% 8,805Eagle Continental 9/2017 WOC 9,679Gripe FIU Continental 8/2017 16.0 100% 10,175

Lease Operator Spud DateIP-30Boe/d

Liquids %

Lateral Length

Jordan Devon 4/2017 1,636 51% 10,050ML Devon 9/2016 1,766 48% 4,676Carpenter Cimarex 10/2017 WOC 4,786Privott Devon 10/2016 4,308 57% 10,112Lorene Continental 7/2017 5,483 30% 10,186Geronimo 89 Energy 6/2017 895 58% 4,797Rafter J Ranch Marathon 7/2017 1,017 27% 4,111

12


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

1

2

3

4

5

6

7

9

8

OilCondensate

Dry Gas

Unit’s Acreage

Meramec

Woodford

1

3

2

4

56

8

9

10

11

12

13

14

15

7

10

Denotes Unit working interest

0%

50%

100%

150%

200%

250%

$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50

IRR

%

Stack Condensate Stack Dry Gas Stack Oil

11

12

14

13

15


Type CurveSTACK ExtMeramec

STACKOsage

IP - 30 (Boe/d) 1,040 1,203

ROR 77% 35%

Total EUR (Mboe) 920 956

% Liquids 63% 57%

Lateral Length 5,000’ 5,000’

Well Cost ($mm) $6.2 $7.3

13

Lease Operator Spud DateIP-30Boe/d

Liquids %

Lateral Length

Cox Tapstone 9/2017 1,583 20% 10,009Rebecca Tapstone 11/2017 788 50% 10,130Randi Tapstone 7/2017 678 43% 10,178Bond Comanche 6/2017 1,305 40% 4,300Walters Newfield 7/2017 1,598 77% 10,179Ward Comanche 106/2015 627 75% 4,162Medrill Sandridge 10/2016 1,164 85% 4,681Schoeppel Chesapeake 7/2016 865 54% 4,764McConnell Comanche 6/2016 532 46% 4,493Drinnon Tapstone 5/2016 793 22% 4,111Olive Lee Devon 3/2014 1,755 19% 4,594Bivens Tapstone 11/2017 1,363 48% 4,436

Lease Operator Spud DateIP-30

Mmcfe/dGas %

Lateral Length

Stephen Chesapeake 9/2016 4.6 97% 4,925Tucker Council Oak 6/2017 8.1 99% 4,378

10

5

6

7

8

11 13

9

4

3

Oil

Condensate

Dry Gas

12

1

Denotes Unit working interest

Unit’s Acreage

Meramec

Osage

1

2

3

4

5

6

7

8

9

10

1

23

45

6

7

89

0%

50%

100%

150%

200%

$60 / $2.50 5/1 Nymex $70 / $3.00 $80 / $3.50

IRR %

Stack Ext Meramec Stack Osage


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

11

12

13

14

12

11

13

10

14


14

STACK – Growing into Core Areafor Unit Petroleum

Gas NGL Oil

Quarterly Net BOE

Geology• Stacked drilling targets in Osage,

Meramec and Woodford• Red Fork Potential in some areas• Sands consistently present across play

Land• 17,000 net acres in STACK(1)/STACK

West(2)

• 85% HBP provides hydrocarbon mix optionality

• 100 - 150 potential operated locations with working interest of 40 - 60%

• 500 - 900 potential non-operated locations with working interest of ~5%

Operations• Running one Unit Drilling rig• Participating ~50 non-op wells in 2018• Focused on oil and wet gas window• Dry gas delayed until gas margins and

takeaway capacity improves

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

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

Potential location counts based upon:(1) 4-6 wells/section(2) 2-4 wells/section

JASPER

POLK

3D AREA494 mi.²

HARDIN

Prior Years DrillingHorizontal Wells

TYLER

Gilly Field

Wilcox – Conventional Stacked Over-Pressured Intervals Provide Low Cost Homerun Potential

15

$/MCFE

Overall Wilcox Drilling Program Results Drilled 170 operated wells since 2003

(160 vertical, 10 horizontal) Program ROR > 80% Operated with working interest ~ 92% Production: ~ 110 MMcfe/d (42% liquids) Running one Unit Drilling rig

Gilly Field – World Class Wet Gas Reservoir 500 Bcfe stacked pay gas resource Cumulative production ~ 115 Bcfe Average EUR of 10-20 Bcfe per well Typical well ~ $6 MM cost, ROR > 100%

Unit’s Wilcox Competitive Advantages Premium Gulf Coast pricing for oil and gas Wet Gas/Condensate provides margin uplift Large 3D seismic database provides consistent

stream of exploratory prospect ideas Conventional over-pressured reservoirs provide

homerun potential at low acreage costs0.40

0.80

1.20

1.60

2.00

0

10

20

30

40

2012 2013 2014 2015 2016 2017 2018Projected

Gas Oil NGLs LOEX ($/MCFE)

Wilcox Annual ProductionBCFE

Wilcox – Exceptional Recompletion & Workover Results

16

2017 Composite Gross Production from Recompletions and Workovers28 Recompletions & 13 Workovers Total Cost: $15MM

Start of Year9.0 MMcfd300 bopd

End of Year34.0 MMcfd

900 bopd• 2016 recompletion/workover

results20 recompletions7 workoversTotal cost: $10 millionProduction increase >1,000%

• Remaining recompletion inventory ~ 80 zones

• Continue to add to inventory with new drilling

Wilcox Trend Provides an Extensive Play Area

Wilcox Strategy for Future Growth Continue development of Gilly Field

area with vertical and horizontal drilling and over 80 stacked pay recompletion/workover opportunities in existing wells

Drill and delineate inventory of exploratory prospects with homerun potential (e.g. Wing/Cherry Creek/Brandt prospects)

Utilize horizontal drilling to extend field boundaries and accelerate reserve recovery (e.g. NE Segno/Village Mills Fields)

18

Rig Fleet Presence in Key Regions

10

10

55

146

Area # of RigsMid‐Continent 18

Bakken 4Niobrara 1Permian 7Pinedale 1Gulf Coast 2

Total 33

Current Rigs Operating(1)

95 rig fleet

69% electric 54% 1,500 HP or greater 35 equipped with skidding or walking systems 26 additional can be skidded

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

11th and 12th BOSS rigs

20 ≤800 HP: 21%71 1,000-1,700 HP: 75%

4 ≥2,000 HP: 4%

(1) As of May 30, 2018.

19

SCR Rigs Continue to Make anImportant Contribution

0

5

10

15

20

25

30

35

40

May 5, 2016 Dec. 31, 2016 Sept. 4, 2017 Dec. 31, 2017 May 30, 2018

A/C SCR

• At industry trough – 13 drilling rigs operating

• Currently, 33 drilling rigs operating

• All BOSS rigs operating

• 23 SCR rigs operating7

12

26

21

6

910 10

22

10

20

Average Dayrates and Margins (1)

Average Rig U

tilization

Mar

gins

and

Day

rate

s

$0

$5,000

$10,000

$15,000

$20,000

2014 2015 2016 2017 Q1'18

Margins Dayrates Average Rig Utilization

100%

75%

50%

25%

0%

(1) See Reconciliation of Average Daily Operating Margin Before Elimination of Intercompany Rig Profit and Bad Debt Expense in Appendix(also available at www.unitcorp.com/investor/reports.html).

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

• Utilization increased from low in Q2 2016

• Margins improved from Q2 2017 forward

21

The BOSS Drilling Rig

Optimized for Pad Drilling Multi-direction walking system

Faster Between Locations Quick assembly substructure 32-34 truck loads

More Hydraulic Horsepower (2) 2,200

horsepower mud pumps

1,500 gpm availablewith one pump

Environmentally Conscious Dual-fuel capable

engines Compact location

footprint

All ten BOSS rigs currently under contract

11th BOSS rig under construction

12th BOSS rig under contract (components being assembled)

22

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

Superior Pipeline

Superior Joint Venture Overview

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

• Access to additional growth capital• To be governed by new board of directors

• Four directors from Unit• Four directors from SP Investor Holdings

Implied Valuation of$600 million*

SP Investor Holdings LLC50% 50%

* 2017 Adjusted EBITDA of $51.7 million.

23

(in thousands except leverage ratios) 3/31/2018 Pro‐Forma

Long term debtBank $ 147,700 $ 0Bonds (net of discount & issuance cost) 642,822 642,822

Total $ 790,522 $ 642,822

Cash 752 150,444Unused bank commitment 325,513 423,213

Total liquidity (1) $ 326,265 $ 573,657

Adjusted EBITDA $ 328,688 $ 302,927

Net debt leverage ratio 2.40x 1.63x

Superior Transaction

Unit Corporation Pro-Forma

(1) On May 10, 2018, Superior entered into a five year $200 million senior secured revolving credit facility with an option to increasethe credit amount up to $250 million, subject to certain conditions.

24

Midstream Core Operations

Appalachia 66,000+ dedicated acres 53 miles of gathering pipeline Q1’18 average gathered volume

of 106.5 MMcf/d

TulsaHeadquarters

Hemphill

Reno

Bellmon

Segno

Processing facilities

Gathering systems

Panola

Key Metrics

• 22 active systems

• Three natural gas treatmentplants

• 340 MMcf/d processing capacity

• Q1’18 average processing volume of 151 MMcf/d

• Approx. 1,452 miles of pipeline

East Texas 62 miles of gathering

pipeline 120 MMcf/d dehy capacity Q1’18 average gathered

volume of 84.9 MMcf/d

Texas Panhandle 47,000+ dedicated acres 135 MMcf/d processing capacity 331 miles of gathering pipeline

Northern Oklahoma and Kansas 2,000,000+ dedicated acres 193 MMcf/d processing capacity 609 miles of gathering pipeline

Central & Eastern OK 62,000+ dedicated acres 12 MMcf/d processing capacity 397 miles of gathering pipeline

PittsburghRegional office

Pittsburgh Mills

Brook Field

Snow Shoe

Bruceton Mills

25

Midstream Segment Contract Mix

Contract Mix Based on Margin

Fee BasedCommodity Based

85%41%

59%

15%

Contract Mix Based on Volume

Fee BasedCommodity Based

49%35%

65%51%

2010 Q1 ‘2018

Unit vs. 3rd Party Margin Contribution

3rd PartyUnit

41% 40%60%59%

26

Debt Structure – No Near-Term Maturities

* Drilling rigs are not included in borrowing base.

Senior Subordinated Notes

$650 million, 6.625%

10-year, NC5; maturity 2021

Key Covenants Interest coverage ratio ≥ 2.25x(1)

Secured Bank Facility (Redetermined April 2018) * Borrowing Base and

Elected Commitment $525/$475 million

Outstanding(2) $147.7 million

Maturity April 2020

Key Covenants Current ratio ≥ 1.0 to 1.0(1)

Senior Indebtedness ratio ≤ 2.75(1)

(1) As defined in Indenture/Credit Agreement.(2) As of March 31, 2018.(3) Pro forma after close of Superior transaction.

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

3/31/20186.01x(1,2)

3/31/2018 Actual2.18x(1,2)

0.45x(1,2)

Pro forma3.44x (3)

0.0 (3)

Pro forma$425 million (3)

$0 (3)

27

Segment Contribution

Oil and Natural Gas Contract Drilling Midstream

Revenues ($ millions) Adjusted EBITDA ($ millions)(1)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2014 2015 2016 2017 Q1'18

$0

$200

$400

$600

$800

2014 2015 2016 2017 Q1'18

$205

$1,573

$854

$602

$740

$787

$410

$252

$313

$89

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

28

Operating Segment Capital Expenditures (1)

$0

$500

$1,000

$1,500

2013 2014 2015 2016 2017 2018 Forecast

Oil and Natural Gas Contract Drilling Midstream

(In Millions)

(1) Net of acquisitions and plugging liability revisions.

29

APPENDIX

30

Non-GAAP Financial Measures - Corporate

Adjusted EBITDA

Years endedDecember 31,

($ In Millions) 2018 2014 2015 2016 2017

Net Income (Loss) $16 $8 $136 ($1,037) ($136) $118Income Taxes 14 3 87 (627) (71) (58)Depreciation, Depletion and Amortization

47 57 403 353 208 209

Impairments --- --- 158 1,635 162 ---Interest Expense 9 10 17 32 40 38 (Gain) loss on derivatives (15) 7 (30) (26) 23 (15)Settlements during the period of matured derivative contracts

(1) (2) (6) 47 10 ---

Stock compensation plans 4 7 24 21 14 18 Other non-cash items 1 (1) 5 3 3 3 (Gain) loss on disposition of assets --- --- (9) 7 (3) ---Adjusted EBITDA $75 $89 $785 $408 $250 $313

2017

Three months endedMarch 31,

31

Non-GAAP Financial Measures - Segments

Segment Cash Operating Margin

(1) After intercompany eliminations and does not include allocation of G&A expense.

Unit PetroleumIncome (Loss) Before Income Taxes (1) $ 36 $ 36 $ 199 $ (1,631) $ (102) $ 125

Depreciation, Depletion and Amortization 22 31 276 252 114 102Impairment of Oil and Natural Gas Properties --- 77 1,599 162 ---

Adjusted EBITDA $ 58 $ 67 $ 552 $ 220 $ 174 $ 227

Unit DrillingIncome (Loss) Before Income Taxes (1) $ (5) $ 1 $ 42 $ 45 $ (13) $ (4)

Depreciation and Impairment 13 13 160 64 47 56Adjusted EBITDA $ 8 $ 14 $ 202 $ 109 $ 34 $ 52

Superior PipelineIncome (Loss) Before Income Taxes (1) $ 2 $ 3 $ 2 $ (30) $ 2 $ 8

Depreciation, Amortization and Impairment 11 11 48 71 46 44Adjusted EBITDA $ 13 $ 14 $ 50 $ 41 $ 48 $ 52

($ In Millions) 2018 2014 2015 2016 20172017



32

Non-GAAP Financial MeasuresReconciliation of Average Contract Drilling Daily Operating Margin

Before Elimination of Intercompany Rig Profit and Bad Debt Expense

(In thousands except for operating daysand operating margins) 2017 2014 2015 2016 2017

Contract drilling revenue $37,185 $45,989 $476,517 $265,668 $122,086 $174,720

Contract drilling operating cost 29,227 31,667 274,933 156,408 88,154 122,600

Operating profit from contract drilling $7,958 $14,322 $201,584 $109,260 $33,932 $52,120

Add:

Elimination of intercompany rig profit and bad debt expense

- 434 29,343 3,991 235 1,620

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

7,958 14,756 230,927 113,251 34,167 53,740

Contract drilling operating days 2,291 2,849 27,516 12,681 6,374 10,964

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

$3,474 $5,179 $8,392 $8,931 $5,360 $4,901

2018



33

Income (loss) before income taxes $35.2 $1.5 $4.6 ($29.8) $11.5

Pro-forma Intercompany impact 0.2 --- (0.9) 0.7 ---

Pro-forma Interest impact --- --- (0.5) 2.3 1.8

Pro-forma income (loss) before income taxes $35.4 $1.5 $3.2 ($26.8) $13.3

Pro-forma taxes 9.8 0.4 0.4 (7.4) 3.2

Pro-forma net income (loss) 25.6 1.1 2.8 (19.4) 10.1

Net income attributable to non-controllinginterest

--- --- (1.6) --- (1.6)

Net income attributable to Unit $25.6 $1.1 $1.2 ($19.4) $8.5

Pro-forma Reconciliation

Pro-forma Reconciliation of First Quarter 2018 Results as if Superior Transaction Occurred 1-1-2018

(In millions) ContractDrilling Midstream Other

TotalConsolidated

Oil and Natural Gas

34

Derivative Summary

2018 2019 2020Q2 Q3 Q4

CRUDE:CollarsVolume (Bbl) -- -- -- -- --Weighted Avg Floor -- -- -- -- --Weighted Avg Ceiling -- -- -- -- --3-Way CollarsVolume (Bbl) 182,000 184,000 184,000 730,000 --Weighted Avg Floor $47.50 $47.50 $47.50 $57.50 --Weighted Avg Subfloor $37.50 $37.50 $37.50 $47.50 --Weighted Avg Ceiling $56.08 $56.08 $56.08 $71.90 --SwapsVolume (Bbl) 364,000 368,000 368,000 -- --Weighted Avg Swap $53.52 $53.52 $53.52 -- --

NATURAL GAS:CollarsVolume (MMBtu) 2,730,000 2,760,000 -- -- --Weighted Avg Floor $2.67 $2.67 -- -- --Weighted Avg Ceiling $2.97 $2.97 -- -- --3-Way CollarsVolume (MMBtu) 1,820,000 1,840,000 1,840,000 -- --Weighted Avg Floor $3.00 $3.00 $3.00 -- --Weighted Avg Subfloor $2.50 $2.50 $2.50 -- --Weighted Avg Ceiling $3.51 $3.51 $3.51 -- --SwapsVolume (MMBtu) 3,640,000 3,680,000 2,150,000 -- --Weighted Avg Swap $2.99 $2.99 $3.01 -- --Basis SwapsVolume (MMBtu) 2,730,000 2,760,000 2,450,000 18,250,000 10,950,000Weighted Avg Swap ($0.48) ($0.48) ($0.52) ($0.43) ($0.28)

PROPANE:SwapsVolume (Bbl) 136,500 138,000 -- -- --Weighted Avg Swap $32.144 $32.144 -- -- --

CrudeNatural

Gas MB C2 MB C3MB C3 $ per barrel MB NC4 MB iC4 MB C5+ CW C2 CW C3 CW NC4 CW iC4 CW C5+

2018 $66.545 $2.851 $0.282 $0.876 $36.786 $0.973 $1.089 $1.524 $0.101 $0.764 $0.789 $1.038 $1.485

2019 $61.403 $2.741 $0.272 $0.808 $33.943 $0.898 $1.005 $1.406 $0.097 $0.705 $0.728 $0.958 $1.370

2020 $56.464 $2.708 $0.268 $0.743 $31.213 $0.826 $0.924 $1.293 $0.096 $0.648 $0.669 $0.881 $1.260

2021 $53.259 $2.726 $0.270 $0.701 $29.441 $0.779 $0.872 $1.219 $0.096 $0.612 $0.631 $0.831 $1.188

2022 $51.406 $2.779 $0.275 $0.677 $28.417 $0.752 $0.842 $1.177 $0.098 $0.590 $0.609 $0.802 $1.147

Thereafter $51.406 $2.779 $0.275 $0.677 $28.417 $0.752 $0.842 $1.177 $0.098 $0.590 $0.609 $0.802 $1.147

35

Q2 2018 Economic Prices

Strip Case*

*Strip prices as of 5/1/2018.

BANK OF AMERICA MERRILL LYNCHENERGY CREDIT CONFERENCE

June 6, 2018

IPAA Oil & Gas Investment Symposium - Unit Corporation - A … · · 2018-04-10• Retains 50% equity interest • Received $300 million • Retains operational control of Superior

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