Barclay’s CEO Energy ConferenceSeptember 11, 2013

Overview of Operations

Tulsa based diversified energy company incorporated in 1963

Integrated approach to business allows Unit to balance its capital deployment through the various stages of the energy cycle

16

18

Bakken

Casper Office

16125 Unit Rigs

E&P Plays

Mid-Stream Operations

Arkoma Basin

Marcellus

North La/ East Texas Basin

Gulf Coast Basin

Houston Office

Oklahoma City Office

Tulsa Headquarters

Anadarko Basin

Permian Basin

2Integrated Business ApproachIntegrated Business Approach

75

3

Key Growth Points

Exploration & Production– 212% average production replacement since 2003– 130% increase in liquids production since Q1 2009, when Unit began focusing

almost entirely on increasing liquids production– Proved reserves: 150 MMBoe (1)

Drilling– Grown rig count 42% since 2003– Sold 17 rigs since 2003– 125 drilling rig fleet

Mid-Stream– 144% increase in natural gas processing volumes since 2008– 177% increase in daily liquids sold volumes since 2008– 1,411 miles of pipeline

Strong Balance Sheet– Remains conservatively financed as the company has grown

(1) As of 12/31/2012.

Capital Allocation Criteria

Oil and Natural Gas SegmentMinimum 15% risk-adjusted ROR for new well proposals

Contract Drilling SegmentNew build rigs – minimum contract term of 2 to 3 years at a day ratesufficient to provide a 100% cash on cash payout during a 3 year term

Rig Refurbishments – minimum contract term sufficient to provide a 100%cash on cash payout during the initial term

Midstream SegmentMinimum 25% risk-adjusted ROR for POP/POI projectsMinimum 15% risk-adjusted ROR for Fee Based projects

4

5

Core Upstream Producing Areas

NGL23%

Oil21%

Gas56%

NGL23%

Oil15%

Gas62%

Beginning in late 2008, implemented strategy of increasing focus on liquids-rich and oil prospects

– Forecast 43% liquids production for 2013

Key focus areas include:

– Granite Wash (Texas Panhandle)

– Marmaton (Oklahoma Panhandle oil play)

– Wilcox (Gulf Coast)

– Mississippian (Kansas)

2012 reserves of 150 MMBoe were 62% natural gas and 79% proved developed

– Reserve life of approximately 10 years

2012 Proved Reserves Q2 2013 Daily Production

Proved Reserves: 150 MMBoe Daily Production: 45.2 MBoe/d

MarmatonGranite Wash

Wilcox

Mississippian

GraniteWash

Wilcox

Marmaton

0%

100%

200%

300%

400%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

Track Record of Reserve Growth

6

0

20

40

60

80

100

120

140

160

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

(1) The Company uses the reserve replacement ratio as an indicator of the Company's ability to replenish annual production volumes and grow its proved reserves, including by acquisition, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation.

(2) 164% based on previous SEC reporting standards.

Stable and consistent economic growth of oil and natural gas reserves of at least 150% of each year’s production

222% average annual reserve replacement over last 29 years

Reserve growth driven by Oklahoma and Texas activity and a shift from vertical to horizontal / liquids-rich drilling

Proved Reserves (MMBoe)

Annual Reserve Replacement(1)

Natural GasOil / NGLs

2003 – 2012 CAGR: 15%

166% 171% 176%202%

285%261%

221%186%

Minimum Target: 150%

164%(2)

116

4858

6979

8695 96

104

150

337%

113%

7

Increasing Production whileImproving Commodity Mix

0

10

20

30

40

50

2008 2009 2010 2011 2012 2013E

Natural GasOil / NGLs Production Range

29 28

43134

Annual Production (MBoe/d)

Net Wells Drilled:

27

33

39

88 82

55%

46

45

80

28%

8

Granite Wash Play

Noble acquisition strategic fit with existing UPC leasehold

Total 47,000 net acres in the Texas Panhandle Core Area (81% HBP)

Approximately 800 potential drilling locations

HIGHLIGHTS

Completed 65 operated horizontal wells since 2008

Production up 48% first half of 2013 over first half of 2012

Calculated ROR = 49% - 70% (Flat $90 oil, $30 NGL, $3.25 gas)

Current AFE CWC: $5.3 MM

2013 ACTIVITY

First half ‘13 = average net 86 MMcfe per day(46% oil & NGLs)

First half ‘13: 8 wells completed – 30 day IP = 4.5 MMcfeper day

4-6 Unit rigs: First sales on 28 gross wells

Estimate capital expenditures $145 million net

11,000’ +/-200’

13,400’ +/-200’

GW Type Log - Buffalo Wallow Field

Total 115,000 net acres in focus area (53% HBP)

150 potential locations on 640 acre spacing

HIGHLIGHTS

Completed 108 operated horizontal wells since 2010

Production up 50% in first half 2013 over 2012

Calculated ROR 60% (Flat $90 oil, $30 NGL, $3.25 gas)

Current AFE CWC: $2.7 million per well

2013 ACTIVITY

First half ‘13 average net 4,000 Boe per day (92% oil & NGLs)

First half ‘13: 23 wells completed – 30 day IP = 350 Boeper day

Two Unit rigs – estimate 46 gross completed wells

Estimate capital expenditures $105 million net

9

Marmaton Oil Play

FocusArea

WILCOX HIGHLIGHTS

Initial UPC discovery – 2003

2003 - 2012

Completed 120 wells

Gross cumulative production: 143 Bcfe (43% oil & NGLs)

2013 ACTIVITY

Q2 2013 = average net 38 MMcfe per day

Two Unit rigs in Wilcox; 12 – 14 gross wells

Estimated AFE CWC: $5.4 million

Drilling first horizontal well ($9.5 million)

Estimate capital expenditures $78 million net

10

Wilcox Liquids Play

Unit Prospect Area72,000 net acres

“Gilly” FieldDiscovery

“Gilly” Field Discovery220 Bcfe net resource potential

2011-2012 wells2013 wellsFuture wells

“Gilly” Field Discovery – announced July 2012

Total resource potential = 302 Bcfe gross; 220 Bcfe net (30 Bcfe net proved YE 2012)

Eight Wilcox potential pay zones (4 zones currently tested)

Seven “Gilly” Field producing wells

11

Mississippian Play

Central Kansas Uplift

Mississippian Trend

Focus Area

Initial Well

105,000 Net Acres

Mississippian Wells

Total 118,000 net acres in focus area (5% HBP)

Approximately 300 potential locations (320 acre spacing)

HIGHLIGHTS

Seven horizontal Miss wells completed

30 day average IP 238 Boe per day

Initial well completed May 2012; cumulative production53 MBoe/14 months; Current daily – 85 Boepd

Estimated reserve range = 125 - 180 MBoe

Estimated AFE CWC: $3.0 million

2013 ACTIVITY

Pipeline and plant construction estimated completionin Q3

One Unit rig and potential second rig in Q4

First sales on 13 gross wells

Estimate capital expenditures $40 million net

12

Significant Drilling Presence inAttractive Producing Regions

125 Unit Rigs

HoustonOffice

TulsaHeadquarters

OklahomaCity Office

18

16

75

CasperOffice

16

125 rig fleet

– Fleet average ~1,200 HP rating;~16,600 ft depth capacity

– 97% of contracted rigs drilling horizontal wells

51% utilization rate for Q2 2013

– 64% of 45 1,200-1,700 HP rigs under contract

Refurbished / upgraded 19 rigs in 2011and 15 rigs in 2012

2012 – placed 2 new build rigs into service (1,500 HP)

Contracted Rig

Commodity MixGeographical Location

Liquids Rich 99%

Dry Gas1%

AnadarkoBasin60%E. TX, LA

GC, S. TX13%

Rockies/Bakken

27%

Note: Based on 65 contracted rigs. All charts represent total 125 rig fleet.

13

Average Dayrates and Margins (1)

0

30

60

90

$0

$5,000

$10,000

$15,000

$20,000

2009 2010 2011 2012 6 mos. '13

(1) Margins are before elimination of intercompany rig profit.

Margins Day Rates

Mar

gin

s /

Day

Rat

es($

)A

verage Nu

mber of R

igs Utilized

Rigs Utilized

14

Diverse and Versatile Rig Fleet

Average Depth Capacity: 16,600 feet83 rigs equipped with integrated top drives

4531 38 5 6Number of Rigs: 70%

0

20%

40%

60%

80%

100%

400-700 h.p. 750-1,000 h.p. 1,200-1,700 h.p. 2,000 h.p. >2,500 h.p.

UtilizationPercentage

(52% as of 9/6/13)

29 of 45 working

15

Optimized for Pad Drilling Multi-direction walking systemFaster Between Locations Quick assembly substructure 32 truck loadsMore Hydraulic Horsepower (2) 2,200 horsepower mud pumps 1,500 gpm available with one pumpEnvironmentally Conscious Dual-fuel capable engines Compact location footprint

Introducing the New BOSS Drilling Rig

16

Granite Wash 29,000 dedicated acres 1 processing facility 135 MMcf/d processing capacity 308 miles of gathering pipeline $12MM capital budget for 2013

Mississippi Lime 875,000+ dedicated acres 7 processing facilities 157 MMcf/d processing capacity* 484 miles of gathering pipeline $34.5MM capital budget for 2013

Marcellus Shale 43,000 dedicated acres 33 miles of gathering pipeline

Central & Eastern OK 197,000+ dedicated acres 540 miles of gathering pipeline 1 processing facility with

18 MMcf/d processing capacity 2 treating facilities with

combined capacity of 190 GPM

East Texas 46 Miles of gathering

pipeline

*Includes 25 MMcf/d from Reno, which will be operational in Q3

Indicates Company Headquarters in Tulsa, OklahomaIndicates Regional office in Pittsburgh, Pennsylvania

Hemphill

Reno

Bellmon

Segno

Pittsburgh Mills

Mid-Stream Core Operations

Processing facilities

Gathering systems

17

Historical Performance

NGLs Volumes (Bbl / d)

Contract Mix (Based on Operating Margin)(1)Contract Mix (Based on Volume)(1)

Historical Daily Gathering Volumes (MMBtu / d)

(1) POP represents percent of proceeds. POI represents percent of index.

2012 Q2 2013

Fee Based39%

POP59%

POI2%

Fee Based51%

POP47%

POI2%

2012 Q2 2013

Fee Based25%

POP69%

POI6% Fee Based

24%

POP72%

POI4%

0

100,000

200,000

300,000

400,000

2009 2010 2011 2012 6 mos. '12 6 mos. '130

5,000

10,000

15,000

2009 2010 2011 2012 6 mos. '12 6 mos. '13

18

Midstream Segment 2013 Outlook

Mississippian Reno County, KS: 25 MMcf/d Total Processing Capacity 5 MMcf/d refrigeration plant – operational Q3 2013 20 MMcf/d cryogenic plant – operational Q3 2013

Mississippian Bellmon: 90 MMcf/d Total Processing Capacity 30 MMcf/d cryogenic plant installed 60 MMcf/d cryogenic plant – operational Q4 2013

164 expected well connects in 2013 Connected 83 wells by the end of Q2

Consistent growth through greenfield construction of pipelines and processing plants in unconventional resource basins

19

Balance Sheet Summary

Total Assets 3,899.5 3,761.1

Long-Term DebtSenior Subordinated Notes 645.5 645.3Bank Facility 70.0 71.1

Total Long-Term Debt 715.5 716.4

Shareholders’ Equity 2,079.5 1,974.3

Credit Line Undrawn 430.0 428.9

Long-Term Debt toTotal Capitalization 26% 27%

(In Millions)

6/30/13 12/31/12

20

Debt Structure (1)

Senior Subordinated Notes $650 million, 6.625%

10-year, NC5; maturity 2021

Unsecured Bank Facility Borrowing Base $800 million

Elected Commitment $500 million

Outstanding $70.0 million

Maturity September 2016

Ratings S&P Moody’s FitchCorporate BB Ba3 BBSenior Subordinated Notes BB- B1 BB-

(1) As of June 30, 2013

0

2,000

4,000

6,000

8,000

10,000

2013 2014

21

Hedges

0

20,000

40,000

60,000

80,000

100,000

2013 2014

Natural GasMMBtu/d

Crude OilBbls/d

Target 50–70% of current year projected oil and natural gas production

$97.94$94.36

$3.65

$4.24

22

Segment Contribution

Oil and Natural Gas Contract Drilling Midstream

(1) See appendix for adjusted EBITDA reconciliation.

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

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2009 2010 2011 2012 6 mos. '13$0

$200

$400

$600

$800

2009 2010 2011 2012 6 mos. '13

$659$707

$871

$1,208

$1,315

$373

$441

$602

$657

$318

23

Capital Expenditures

$0

$500

$1,000

$1,500

2008 2009 2010 2011 2012 2013 Budget

Oil and Natural Gas Contract Drilling Midstream Acquisitions

(In Millions)

Forward-Looking Statement

24

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 the factors discussed or referenced in the “Risk Factors” section of the Company’s Offering Memorandum provided in connection with this offering, 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.

Non-GAAP Financial Measures –Adjusted EBITDA

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

Years ended December 31,($ in Millions) 2009 2010

Net Income ($56) $146Income Taxes (32) 91Depreciation, Depletion and Amortization 177 205Impairment of Oil and Natural Gas Properties 281 -Interest Expense 1 -

Unit PetroleumIncome Before Income Taxes(1) ($121) $176

Depreciation, Depletion and Amortization 115 119Impairment of Oil and Natural Gas Properties 281 -

Adjusted EBITDA $275 $295

Unit DrillingIncome Before Income Taxes(1) $51 $60

Depreciation and Amortization 45 70Adjusted EBITDA $96 $130

Superior PipelineIncome Before Income Taxes(1) $5 $17

Depreciation and Amortization 16 15Adjusted EBITDA $21 $32

2011

$196123281

-4

$200183

-$383

$13580

$215

$1716

$33

Six months ended June 30,2012 2013

$33 $9921 62

163 159116 -

4 8

($27) $123109 107116 -

$198 $230

$94 $4843 35

$137 $83

$7 $410 15

$17 $19

2012

$2316

31928414

($77)211284

$418

$15981

$240

$624

$30

(Gain) loss on unrealized value of commodityderivatives (2) 1 21 (10) (1)

Adjusted EBITDA $373 $441 $602$338 $318 $657