Scotia Howard WeilEnergy Conference

March 22, 2016

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.

2

Unit Corporation: A Diversified Energy Company

3

12

10Casper Casper 

6

Arkoma Basin

Marcellus

North La/ East Texas Basin

Gulf Coast Basin

Houston Houston 

Oklahoma City

Oklahoma City

Tulsa HeadquartersTulsa Headquarters

Anadarko Basin

Permian Basin

54

94 Unit Rigs

E&P Operations

Mid‐Stream Operations

Office Location

12

PittsburghPittsburgh

• Tulsa based, incorporated in 1963

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

We Are Focused on 2016 and Beyond

We have weathered many cycles during our 50+ year history Balance sheet preservation is key Spending within cash flow Reduce debt with excess cash flowManage costs

4

2015 Statistics

5

Exploration & Production– Attained record annual production of 20 MMBoe, a 9% increase year 

over year– Liquids production grew 7% year over year– Proved reserves:  135 MMBoe (1)

Drilling– Eight BOSS rigs placed into service; seven under contract– 94 drilling rig fleet

Mid‐Stream– 13% increase in daily natural gas processing volumes in 2015– 11% increase in daily gathered volumes in 2015– Approximately 1,464 miles of pipeline

(1) As of 12/31/2015.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Oil and Gas Contract Drilling Midstream

6

Segment EBITDA Margins (1) in Line with Pure Play Peers EB

ITDA

 Margins

E&P Company Peer Average

Land Drilling Peer Average

Midstream Peer Average

Source:  E&P:  CRK, EGN, NBL, NFX, QEP, SGY, SM, XEC;    Contract Drilling:  HP, ICD, NBR, PES, PKD, PTEN;    Midstream:  BPL, DPM, ENLK, EPD, ETE, ETP, MMLP, PAA, PAGP, RRMS, SXL 

(1) See Segment EBITDA Margins in Appendix (also available at www.unitcorp.com/investor/reports.html).

Debt Structure – No Near‐Term Maturities

7

Senior Subordinated Notes

$650 million, 6.625%

10‐year, NC5; maturity 2021

Key Covenants   Coverage ratio ≥ 2.25x (1) Actual ratio 7.17x (1,2) 

Unsecured Bank Facility 

Current Borrowing Base  $550 million

Elected Commitment $500 million

Outstanding (2) $281.0 million

Maturity April 2020

Key Covenants Current ratio ≥ 1.0 to 1.0 (1) Actual ratio 2.30x (1,2)

Leverage ratio ≤ 4.0 (1) Actual ratio 2.58x (1,2)(1) As defined in Indenture/Credit Agreement(2) As of December 31, 2015

Ratings S&P Moody’s FitchCorporate B+ B2 BBSenior Subordinated Notes B+ B3 BB‐

Core Upstream Producing Areas

8

18%

43%

33%6%

Gas55%Oil

19%

NGL26%

Key focus areas include:

Gulf Coast:

– Wilcox (Southeast Texas)

Mid‐Continent:

− Hoxbar (Western Oklahoma)

− Granite Wash (Texas Panhandle)

$109 Million 2016 Capital Budget 2015 Daily Production: 54.7 MBoe/d

Granite Wash

Wilcox

Hoxbar

Other

Mid Continent Region

Upper Gulf Coast Region

Wilcox

D & C Spending:  $42 Million

D & C

WorkoverLand & Seismic

Capitalized/Other

G & G

$24 MM

$42 MM

$10 MM

$16 MM

$17 MM

SOHOT

Granite Wash

0

10

20

30

40

50

60

2011 2012 2013 2014 2015 2016 est.

Natural Gas Oil / NGLs Prod. Range

Historical and Projected Production

9

82

Average Production (MBoe/d)

Net Wells Drilled:

33

39

46

80 91 121 35

5550 46‐48

10‐15 est.

JASPER

POLK

3D AREA494 mi.²

HARDIN

Prior Years DrillingHorizontal Wells

Wilcox (Southeast Texas)

Overall Highlights Year End 2015:

Drilled 153 operated wells since 2003(150 vertical, 3 horizontal)

92% average working interest

Q4 ‘15 net avg. production:88 MMcfe/d

42% liquids (12% oil)

Historical ROR:  108%

Average 2015 LOE down 19% to $0.91/Mcfe

2016 Activity:

Complete 4 horizontal Wilcox wells

Complete 8‐10 behind pipe recompletions

Identified 2 new Wilcox project areas

Acquired 165 square mile 3‐D data

Currently leasing

TYLER

Gilly Field

Gilly Field Cross Section

A A’3.8 miles

Temporarily Abandoned Perforations Current Production Future Behind Pipe Recompletions

Lower Wilcox91 Mcfed

*Feb. ‘16 Exit Rate

AllarGU #1

A A’3.8 miles

12

Allar GU #1

Summary

• Recompletion to Lower Gilchrease “B” Sand

• Production increased from 15 Bopdand 445 Mcfd to 300 Bopd and 5,700 Mcfd

AOF Potential:• 23 ‐ 24 MMcfd• 1,200 ‐ 1,300 Bopd

Economics

Est. Actual:  $690,000

Net PW10:  $8.5 million

WI:  100.00%RI:  75.27%

Tubing & Packer Installation

Recomplete to Lower Gilchrease “B” sd.

Hoxbar (Marchand Sand)

13

Marchand Core Case:

EUR: 530 MBoe*

IP30:  802 Boe/d*

Well cost:  $4.9 million

ROR:  30%1

84% liquids (72% oil)

30‐40 core operated locations

• 50% average working interest

30‐35 core non operated locations

• 35% average working interest

2016 Marchand Activity:

0‐1 rig

4 horizontal wells

* 24 total operated and non‐operated wells.

H O X B A R  3 , 0 0 0 ’

Extensional Area

Harper  1‐19HIP30:  2,467 Boe/d

1/15

Harper  1‐19HIP30:  2,467 Boe/d

1/15

Earl 2‐30HIP30: 1,817 Boe/d

8/14

Earl 2‐30HIP30: 1,817 Boe/d

8/14

GB 1‐30H   IP30: 1,367 Boe/d

3/14

GB 1‐30H   IP30: 1,367 Boe/d

3/14

Powers 1‐15HIP30: 1,233 Boe/d

12/14

Powers 1‐15HIP30: 1,233 Boe/d

12/14

Rosey 1H IP30:  1,483 Boe/d

9/14

Rosey 1H IP30:  1,483 Boe/d

9/14

Schenk 18HIP30: 700 Boe/d

6/15

Schenk 18HIP30: 700 Boe/d

6/15

Marchand Horizontal ProducerMarchand Vertical Producer

Brown  1‐11HIP30:  867  Boe/d

1/15

Brown  1‐11HIP30:  867  Boe/d

1/15

1Q1 2016 Strip Price Deck with 1st Production Starting 1/1/2016; see Q1 2016 Economic Prices in Appendix (also available at www.unitcorp.com/investor/reports.html).

$0

$4

$8

$12

$16

Peer 1 Peer 2 Unit Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8

Expertise in Areas of Operations

14

Average:  $9.64

Unit has experienced management and operating teams and is a leader in minimizing operating expenses

Ope

ratin

g Expe

nse / Bo

e(1)

(1)  Data in table is as of Q4 2015.Source:  CRK, EGN, NFX, NBL, QEP, SGY, SM, XEC

Rig Fleet Presence in Key Regions

15

94 rig fleet 

– 69% electric– 56% 1,500 HP or greater– 94 equipped with top drives– 58 equipped with skidding or walking systems

29% total fleet utilization rate for Q4 2015 

Eight BOSS placed into service; seven under contract

Bakken

Niobrara

AnadarkoGranite Wash

Permian WilcoxArea # of RigsAnadarko Basin 5

Bakken 2Granite Wash 2

Permian 3Niobrara 3Wilcox 0Total 15

20 ≤800 HP: 21%70 1,000‐1,700 HP: 75%4 ≥2,000 HP: 4%

Current Rigs Operating

12

10

54

126

16

$0

$5,000

$10,000

$15,000

$20,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Margins Dayrates Average Rig Utilization

Average Dayrates and Margins (1)

(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).

Average R

ig Utilization

Mar

gins

and

Day

rate

s

100%

75%

50%

25%

0%

The BOSS Drilling Rig

17

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 available with one pump

Environmentally Conscious Dual‐fuel capable engines Compact location footprint

Appalachia 66,000+ dedicated acres 49 miles of gathering pipeline Snow Shoe completed Jan. 2016

Midstream Core Operations

18

TulsaHeadquarters

PittsburghRegional office

Hemphill

Reno

Bellmon

Segno

Pittsburgh Mills

Processing facilities

Gathering systems

Panola

Key Metrics

• 25 Active Systems

• Three Natural Gas Treatment Plants

• 340 MMcf/d Processing Capacity

• Approx. 1,464 miles of Pipeline

East Texas 62 Miles of gathering pipeline

Texas Panhandle 50,100 dedicated acres 135 MMcf/d processing capacity 343 miles of gathering pipeline

Northern Oklahoma and Kansas 1,972,000+ dedicated acres 193 MMcf/d processing capacity 567 miles of gathering pipeline

Central & Eastern OK 54,400+ dedicated acres 12 MMcf/d processing capacity 443 miles of gathering pipeline

Brook Field

Snow Shoe

Bruceton Mills

Contract Mix Based on Margin

Fee BasedCommodity Based

85%35%

65%

15%

Contract Mix Based on Volume

Fee BasedCommodity Based

49%32%

68%51%

Midstream Segment Contract Mix

19

2010 2015

Unit vs. 3rd Party Margin Contribution

3rd PartyUnit

41% 42% 58%59%

Appalachian Growth Projects

20

• Completed construction of Snow Shoe Gathering System in Centre County, PAin Q4 2015– First flow in January 2016– Signed contract with new producer to 

connect wells in Q2 2016

• Expansion of Pittsburgh Mills gathering system into Butler County, PA – Completed construction of 

compression station in Q4 2015– Connected new well pad in Feb. 2016– Three additional well pads scheduled 

for connection in 2016 (one in March; two in July)

A P P A L A C H I A N    P R O J E C T S

Segment Contribution

21

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

2011 2012 2013 2014 2015$0

$200

$400

$600

$800

2011 2012 2013 2014 2015

$1,352

$1,573

$854

$1,208$1,315

$758

$385

$603$657 $640

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

Operating Segment Capital Expenditures

22

$0

$500

$1,000

$1,500

2011 2012 2013 2014 2015 2016 Low EndBudget

2016 High EndBudget

Oil and Natural Gas Contract Drilling Midstream Acquisitions

(In Millions)

23

APPENDIX

24

Segment EBITDA MarginDecember 31, 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

RevenuesOil and Gas (Including Cash Flow Derivatives Settled) $318,208 $357,599 $391,480 $552,696 $362,245 $399,771 $514,614 $567,944 $649,718 $740,079 $385,774

Drilling $462,141 $699,396 $627,642 $622,727 $236,315 $316,384 $484,651 $529,719 $414,778 $476,517 $265,668Gas Gathering $100,464 $101,863 $138,595 $181,730 $108,628 $154,516 $208,238 $217,460 $287,354 $356,348 $202,789Derivatives Settled(Non‐designated) $0 $0 $0 $0 ($2,422) $0 ($711) $0 ($1,764) ($6,038) $46,615

ExpensesOil and GasOperating cost $60,779 $81,120 $97,109 $116,239 $87,734 $105,365 $131,271 $150,212 $184,001 $187,916 $166,046DDA $67,282 $108,124 $127,417 $159,550 $114,681 $118,793 $183,350 $211,347 $226,498 $276,088 $251,944Impairment $0 $0 $0 $281,966 $281,241 $0 $0 $283,606 $0 $76,683 $1,599,348

DrillingOperating cost $266,472 $313,882 $304,780 $312,907 $140,080 $186,813 $269,899 $289,524 $247,280 $274,933 $156,408Depreciation and impairment $42,876 $51,959 $56,804 $69,841 $45,326 $69,970 $79,667 $81,007 $71,194 $159,688 $64,449

Gas Gathering and ProcessingOperating Cost $92,467 $88,834 $119,776 $150,466 $87,908 $122,146 $174,859 $187,292 $243,406 $306,831 $161,556Depreciation, amortization,and impairment $3,279 $6,247 $11,059 $14,822 $16,104 $15,385 $16,101 $24,388 $31,191 $47,502 $70,642

G&A $14,343 $18,690 $22,036 $25,419 $24,011 $26,152 $30,055 $33,086 $38,323 $42,023 $35,415

EBITDA MarginOil and Gas 79% 76% 73% 77% 72% 71% 72% 71% 69% 72% 53%Drilling 41% 54% 50% 48% 37% 38% 42% 43% 38% 40% 37%Gas Gathering 6% 11% 12% 15% 16% 18% 14% 11% 12% 11% 16%

G&A AllocationOil and Gas $5,182 $5,767 $7,451 $10,366 $12,226 $12,025 $12,833 $14,288 $18,419 $19,772 $15,962Drilling $7,525 $11,280 $11,947 $11,652 $8,073 $9,492 $12,046 $13,327 $11,758 $12,731 $10,992Gas Gathering $1,636 $1,643 $2,638 $3,400 $3,711 $4,636 $5,176 $5,471 $8,146 $9,520 $8,391

Non‐GAAP Financial Measures

25

(1) Does not include allocation of G&A expense.

Years ended December 31,($ in Millions)Net Income (Loss)Income TaxesDepreciation, Depletion and AmortizationImpairmentsInterest Expense

Unit PetroleumIncome (Loss) Before Income Taxes (1)Depreciation, Depletion and AmortizationImpairment of Oil and Natural Gas Properties

EBITDA

Unit DrillingIncome Before Income Taxes (1)Depreciation and Impairment

EBITDA

Superior PipelineIncome Before Income Taxes (1)Depreciation, Amortization and Impairment

EBITDA

2011$196123281‐4

$200183‐

$383

$13580

$215

$1716$33

2012$2316

31928414

($77)211284$418

$15981

$240

$624$30

(Gain) loss on derivatives not designated ashedges and hedge ineffectiveness

Settlements during the period of maturedderivative contracts

(Gain) loss on disposition of assets

(2) 1

Adjusted EBITDA $603 $657

2015$(1,037)

(627)355

1,63532

$(1,631)252

1,599$220

$4564

$109

$(30)71

$41

(26)

$385

46‐ ‐

2013$185117334‐15

$239226‐

$465

$9671

$167

$1133

$44

8

$640

(2)

2014$13687

40515817

$19927677

$552

$42160$202

$248

$50

(30)

$758

(6)

Adjusted EBITDA

71 ‐ (17) (9)

Reconciliation of Average Daily Operating MarginBefore Elimination of Intercompany Rig Profit and Bad Debt Expense

26

Non‐GAAP Financial Measures

Years ended December 31,(In thousands except for operating daysand operating margins) 20152011 2012  2013 2014

Contract drilling revenue $ 484,651 $ 529,719 $ 414,778 $ 476,517 $ 265,668

Contract drilling operating cost 269,899 289,524 247,280 274,933 156,408

Operating profit from contract drilling 214,752 240,195 167,498 201,584 109,260

Add:

Elimination of intercompany rig profit andbad debt expense 19,900 15,583 17,416 29,343 3,991

Operating profit from contract drillingbefore elimination of intercompany rigprofit and bad debt expense 234,652 255,778 184,914 230,927 113,251

Contract drilling operating days 27,619 26,704 23,720 27,516 12,681

Average daily operating margin beforeelimination of intercompany rig profitand bad debt expense $ 8,496 $ 9,578 $ 7,796 $ 8,392 $ 8,931

27

Derivative SummaryCrude 2016 2017

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4CollarsVolume (Bbl) 195,650  468,650  133,400  133,400  ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Floor $46.360  $40.714  $47.500  $47.500  ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Ceiling $55.619  $49.880  $56.400  $56.400  ‐‐ ‐‐ ‐‐ ‐‐

3‐Way CollarsVolume (Bbl) 63,700  63,700  128,800  128,800  67,500  68,250  69,000  69,000 Weighted Avg Floor $46.500  $46.500  $47.000  $47.000  $50.000  $50.000  $50.000  $50.000 Weighted Avg Subfloor $35.000  $35.000  $35.000  $35.000  $37.500  $37.500  $37.500  $37.500 Weighted Avg Ceiling $57.000  $57.000  $60.250  $60.250  $63.900  $63.900  $63.900  $63.900 

Natural Gas 2016 2017Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

CollarsVolume (MMBtu) 3,822,000  3,822,000  3,864,000  3,864,000  ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Floor $2.404  $2.476  $2.476  $2.476  ‐‐ ‐‐ ‐‐ ‐‐Weighted Avg Ceiling $2.881  $2.881  $2.881  $2.881  ‐‐ ‐‐ ‐‐ ‐‐

3‐Way CollarsVolume (MMBtu) 1,228,500  1,228,500  1,242,000  1,242,000  1,350,000  1,365,000  1,380,000  1,380,000 Weighted Avg Floor $2.700  $2.700  $2.700  $2.700  $2.500  $2.500  $2.500  $2.500 Weighted Avg Subfloor $2.200  $2.200  $2.200  $2.200  $2.000  $2.000  $2.000  $2.000 Weighted Avg Ceiling $3.260  $3.260  $3.260  $3.260  $3.320  $3.320  $3.320  $3.320 

SwapsVolume (MMBtu) 3,785,000  4,095,000  4,140,000  4,140,000  900,000  910,000  920,000  920,000 Weighted Avg Swap $2.605  $2.596  $2.596  $2.596  $2.795  $2.795  $2.795  $2.795 

Strip Case

Crude Natural Gas MB C2 MB C3 MB NC4 MB iC4 MB C5+ CW C2 CW C3 CW NC4 CW iC4 CW C5+2/16‐1/17 

Avg. $35.338  $2.316  $0.169  $0.401  $0.602  $0.602  $0.789  $0.160  $0.365  $0.550  $0.674  $0.781 2/17‐1/18 

Avg. $41.639  $2.714  $0.200  $0.424  $0.625  $0.632  $0.983  $0.172  $0.380  $0.595  $0.676  $0.967 2/18‐1/19 

Avg. $44.268  $2.800  $0.206  $0.450  $0.665  $0.672  $1.045  $0.178  $0.404  $0.632  $0.719  $1.028 2/19‐1/20 

Avg. $46.086  $2.890  $0.213  $0.469  $0.692  $0.699  $1.087  $0.183  $0.420  $0.658  $0.748  $1.070 2/20‐12/20 

Avg. $47.264  $3.059  $0.225  $0.475  $0.701  $0.709  $1.102  $0.194  $0.426  $0.667  $0.758  $1.084 

Q1 2016 Economic PricesFebruary 2, 2016

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Scotia Howard WeilEnergy Conference

March 22, 2016