BMO Capital MarketsBMO Capital MarketsUnconventional Resource ConferenceUnconventional Resource Conference

Tuesday, January 10, 2012Tuesday, January 10, 2012

2:15 p.m.2:15 p.m.

NY005VRM_1.WOR

Houston Houston Houston Houston Houston Houston Houston Houston Houston OfficeOfficeOfficeOfficeOfficeOfficeOfficeOfficeOffice

Oklahoma Oklahoma Oklahoma Oklahoma Oklahoma Oklahoma Oklahoma Oklahoma Oklahoma City OfficeCity OfficeCity OfficeCity OfficeCity OfficeCity OfficeCity OfficeCity OfficeCity Office

Tulsa HeadquartersTulsa HeadquartersTulsa HeadquartersTulsa HeadquartersTulsa HeadquartersTulsa HeadquartersTulsa HeadquartersTulsa HeadquartersTulsa Headquarters

Casper OfficeCasper OfficeCasper OfficeCasper OfficeCasper OfficeCasper OfficeCasper OfficeCasper OfficeCasper Office

Overview of OperationsOverview of Operations

Integrated Business Approach

(1) Market data as of 1/4/2012.

Andarko Basin55%

Permian Basin4%

North LA/East Texas Basin

3%

Gulf Coast Basin16%

Bakken3%

Arkoma Basin19%

E&P plays

Unit Rigs

New Rigs – 2011

Superior Pipeline's Core Operations

121

7

Tulsa based company founded in 1963 with long history of operations in the Mid-Continent

– Ticker: UNT / NYSE

– Market Cap: $2.3 billion(1)

– Enterprise Value: $2.6 billion(1)

Proved Reserves: 104 MMBoe

Percent Proved Developed: 80%

Drilling Rigs: 128

Miles of Midstream Pipeline: 910

Summary of Business Strengths

Quality upstream asset base with

significant growth potential

Leading drilling services provider

with highly capable fleet

Midstream business generating

incremental margin opportunities

Large development drilling inventory with attractive economics in current price environment, with significant horizontal drilling upside potential

191% average production replacement since 2001

Average 1,200 HP for 128 rig fleet

70% of fleet capable of drilling horizontal wells

120% increase in rig count since 2001

Focus in emerging plays of Granite Wash and Marcellus shale

513% increase in per day natural gas processed volumes since 2004

1,099% increase in per day liquids sold volumes since 2004

Integrated Approach Enhances

Stability and Flexibility

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

Vertical integration offers key advantages and provides industry intelligence on industry dynamics / trends

NGL18%

Oil20%

Gas62%

NGL15%

Oil17% Gas

68%

Core Upstream Producing Areas

2010 reserves of 104 MMBoe were 68% natural gas and 80% proved developed

– Reserve life of approximately 9 years Beginning in late 2008, implemented

strategy of increasing focus on liquids-rich and oil prospects

– Forecast to end 2011 with 38% liquids production

Key focus areas include:– Granite Wash (Texas Panhandle)– Marmaton (Oklahoma Panhandle oil play)– Wilcox (Gulf Coast)

2010 Proved Reserves (MMBoe) Q3 2011 Daily Production (MBoe/d)

PermianBasin

4%

AnadarkoBasin55%

TulsaHeadquarters

ArkomaBasin

19%

North LA/East TexasBasin

3%

Gulf CoastBasin16%

HoustonOffice

Proved Reserves: 104 MMBoeDaily Production: 34.0 MBoe/d(1) Note: Map does not include 3% of proved reserves located in the Bakken shale play.

Track Record of Reserve Growth

(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

218% average annual reserve replacement over last 27 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

2001 – 2010 CAGR: 10%

169% 166% 171% 176%162%

285%261%

221%

186%

113%

0%

50%

100%

150%

200%

250%

300%

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

Minimum Target: 150%

164%(2)

42 45 48

58

69

7986

95 96104

0

20

40

60

80

100

120

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

19

2425

2928

27

33

32

0

7

14

21

28

35

2005 2006 2007 2008 2009 2010 2011E

4297 134 888573

Maintaining Production while Improving Commodity Mix

Natural GasOil / NGLs Low End Projected Production High End Projected Production

Annual Production (MBoe/d)

2005-2011E CAGR: 10%

Net Wells Drilled:

25

2928

26 25

27

2930

33

0

7

14

21

28

35

2007 2008 2009 Q12010

Q22010

Q32010

Q42010

Q12011

2011E

4213497 12 1723 22 31

33

Q22011

20

Production (MBoe/d)

Net Wells Drilled:

2005-2008 CAGR: 16%

34

Q32011

24

Horizontal72%

Vertical28%

Horizontal63%

Vertical37%

Horizontal29%

Vertical71%

Horizontal18%

Vertical82%

Increasing Liquids Focus

In the current commodity price environment, Unit continues to allocate capital towards higher rate of return liquids-rich production

– Liquids-rich focus strategy initiated in late 2008

With attractive economics and evolving technology, Unit continues to shift to more horizontal drilling

– Drilled three operated horizontal wells in 2009

– Drilled 50 operated horizontal wells in 2010

– Plan to drill 70 operated horizontal wells in 2011

Unit Continues to Execute on Its Strategy to Increase Its Liquids Portfolio and Drilling Economics

Annual Production Mix (MBoe/d)

Gross Wells Drilled

2008 2009 2010 2011E

2008 2009 2010 2011E

Liquids25%

Gas75%

Liquids27%

Gas73%

Liquids31%

Gas69%

Liquids37%

Gas63%

Granite Wash Play

Texas Oklahoma7,200’Lower Douglas

9,700’

10,500’

11,100’Upper Morrow

Granite Wash

Type Log

Unit 2011 Horizontal Wells

Unit 2011 Non-op Horizontal Wells

Unit Acreage

Q4 2010 – Q3 2011 Results

– First sales on 21 operated Granite Wash horizontal wells

– Average 30-day IP = 6.7 MMcfe/day

– Average reserves: 4.1 Bcfe(47% oil & liquids)

– Current CWC: $5.4 MM (4,000’ lateral, 11 stage frac)

– Average working interest: 73%

2011 Projected

– 3-4 rigs drilling = 16 operated horizontal wells

– Cap Ex: $85 MM

36,000 net acres

Unit Acreage

Completed and Producing Wells

2011 Wells (first half)

Marmaton Oil Play

+/- 6,200’

+/- 6,00’

Upper

Middle

Lower

400’’

HorizontalLateralTarget

Marmaton Type Log

Unit Focus Area

Q4 2010 – Q3 2011 Results

– First sales on 35 operated Marmaton horizontal wells

– Average 30-day IP = 239 Boe/day

– Average reserves: 130 MBoe(90% oil & liquids)

– Current CWC: $2.7 MM (4,000’ lateral, 16 stage frac)

– Average working interest: 89%

2011 Projected

– 2 rigs drilling = 34 operated horizontal wells

– Cap Ex: $70 MM

84,000 net acres located primarily in Beaver County, OK

2008 Expansion

West WilcoxExpansion (2008)

Approx. 151 sq. mi.

Wilcox SouthExpansion (2009)

Upper

Middle

Lower

7,800’

9,400’

10,500’

11,400’

12,000’

12,900’

2003 to Q3 2011

– Completed 105 wells at 74% success rate

Q1 – Q3 2011 Results

– Completed 13 wells at 69% success rate

– Average 30-day IP rate = 326 Boe/day

– Average reserves: 252 MBoe(50% oil & liquids)

– Average CWC: $3.5 MM

– Average working interest: 95%

2011 Projected

– 1–2 rigs drilling = 17 operated vertical wells

– Cap Ex: $50 MM

48,000 net acres

Wilcox Liquids Play

Completed and Producing Wells

2011 Rig Schedule

Bakken Shale

Currently Drilling Future Drilling

Q1- Q3 2011 Results

– First sales – 10 wells

– Average 30-day IP rate = 1,140 Boe/day

– Average reserves: 736 MBoe86% oil

2011 Projected

– 2 third party rigs drilling = 15 non-op horizontal wells

– Average CWC: $11.0 MM(9,000’ lateral, 28 stage frac)

– Average working interest: 13%

– Cap Ex: $30 MM

13,400 net acres

Acquired Properties

Unit AcreageAcquired Properties

Purchase Price: $30.5 Million

Reserves: 31.2 Bcfe (99% natural gas)

− 83% proved developed

Production: 7.8 MMcfe/day

55,000 Net Acres, 96% HBP

Upside in Woodford Shale and Hartshorne Coal

2011 Upstream Capital Program

$357 million drilling capital budget allocated principally to the liquids-rich Granite Wash, Marmaton, and Wilcox plays

– 8% increase in the drilling budget for 2011

– Approximately $202 million allocated to Granite Wash, Oklahoma Marmaton oil play, and Texas Wilcox field operations (~57% of overall drilling budget)

Current plan will provide Unit with 19% - 22% annual growth in production

Drilling CapEx by Region

2011E CapEx Budget: $435 Million 2011E Capital Budget: $357 Million

Focused Capital Program Emphasizes Higher Return Liquids-Rich Drilling Plays

Total CapEx by Category

Drilling82%

Other18%

Dry Gas 6%

Bakken8%

Other 29%

Wilcox 15%

Granite Wash 27%

MarmatonOil

15%

Significant Drilling Presence in Attractive Producing Regions

HoustonOffice

TulsaHeadquarters

OklahomaCity Office

121 Unit Rigs

15

20

769

CasperOffice

105

7 New Rigs - 2011

128 rig fleet

– Fleet average ~1,200 HP rating; ~16,484 ft depth capacity

– 70% of rigs capable of drilling horizontal

63% utilization rate for Q3 2011

– 100% of 39 1,200-1,700 HP rigs contracted at the end of the third quarter

Recently spent $55 million to refurbish / upgrade 30 rigs

– Identified ~20 additional sub 1,000 HP rigs with upgrade potential

2011 – 7 new build rig program (1,500 HP rigs)

– 2 - 3 year contracts for all 7 rigs, which are deployed in the Bakken shale and Pinedale

2

Average Number of Rigs Utilized

0

25

50

75

100

2007 2008 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011

Diverse and VersatileRig Fleet

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.

Average Depth Capacity: 16,484 feet

UtilizationPercentage

(65% as of 1/4/12)

77 rigs equipped with integrated top drives

30 39 7 6Number of Rigs:New Rigs - 2011:

397

Growing demand from increased

shallow horizontal drilling

activity

72%

39 of 39 working

Conditions Support Improving Dayrates and Margins(1)

Six Consecutive Quarters of Improving Day Rates and Margins(1) Margins are before elimination of intercompany rig profit.

Margins Day Rates

Mar

gins

/ D

ayR

ates

($)

$0

$5,000

$10,000

$15,000

$20,000

2007 2008 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011

Contracted Rig Commodity Mix

Overview of Drilling Fleet

Geographical Location

Rig Type HP Rating

Note: Based on 82 contracted rigs. All charts represent total 128 rig fleet.

Electric 51%

Mechanical49%

Rockies/Bakken22%

Anadarko Basin30%

TX Panhandle

26% Arkoma6%

E. TX, LA, GC, S. TX

12%Barnett

4%

Liquids Rich 63%

Oil 17%

Dry Gas20%

2,000 5% >2,500

5%

450-70024%

1,200-1,70034%

750-1,00032%

Superior Pipeline’s Core Operations

Three natural gas treatment plants

Ten natural gas processing plants

34 active gathering systems 910 miles of pipeline

Average ProcessingPipeline Volume Capacity(miles) (MMbtu/d) (MMcf/d)

Hemphill/Mendota 130 43,700 100Perkins 55 5,600 10Cashion 140 22,500 25Minco 130 7,700 12Panola(1) 45 52,000 -Segno 30 19,900 -

Average ProcessingPipeline Volume Capacity(miles) (MMbtu/d) (MMcf/d)

Hemphill/Mendota 130 43,700 100Perkins 55 5,600 10Cashion 140 22,500 25Minco 130 7,700 12Panola(1) 45 52,000 -Segno 30 19,900 -

(1) Includes two treatment plants.

Historical Performance

NGLs / Condensate Volumes (Bbl / d)

2010 Contract Mix (Based on Operating Margin)(1)2010 Contract Mix (Based on Volume)(1)

Historical Daily Gathering Volumes (MMBtu / d)

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

Fee-Based51%

POP33%

POI16% Fee-Based

15%

POP38%

POI47%

0

50,000

100,000

150,000

200,000

250,000

2006 2007 2008 2009 2010 9 mos.2011

0

2,000

4,000

6,000

8,000

2006 2007 2008 2009 2010 9 mos.2011

10,000

Balance Sheet Summary

Working CapitalWorking Capital $57.9$57.9 $41.1$41.1

Total Assets 3,165.3 2,669.2

LongLong--Term DebtTerm DebtSenior Subordinated NotesSenior Subordinated Notes 250.0250.0 ------Bank FacilityBank Facility 55.455.4 163.0163.0

Total LongTotal Long--Term DebtTerm Debt 305.4305.4 163.0163.0

Shareholders’ Equity 1,910.4 1,710.6

Credit Line UndrawnCredit Line Undrawn 194.6194.6 162.0162.0

Long-Term Debt toTotal Capitalization 14% 9%

(In Millions)

9/30/11 12/31/10

Senior Subordinated Notes

• First-time issuer (May 2011)

• $250 million aggregate principal amount

• 10-year maturity (2021)

• 6 5/8% coupon

Segment Contribution

Unit Petroleum Unit Drilling Superior Pipeline

(1) See EBITDA reconciliation.

Other

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

$1,358

$882

$710

$754

$371

$442$863

$436

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2008 2009 2010 9 mos. 2011$0

$200

$400

$600

$800

2008 2009 2010 9 mos. 2011

Adjusted Earnings per Share(1)

(1) See Adjusted EPS reconciliation to EPS.

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

2006 2007 2008 2009 2010 2011

First 9 mos. Year-End

Hedges

Natural Gas

0

20,000

40,000

60,000

80,000

100,000

2011 2012

MMBtu/d

$4.70

$5.24

Crude OilBbls/d

Target 50–70% of current year projected oil and natural gas production– Crude oil – 63% in 2011– Natural gas – 60% in 2011

Primarily utilize swaps and collars– Current hedge portfolio consists of swaps

Natural Gas Liquids− Hedged 2,535 Bbls/day for balance of 2011 (40% of Q3 ’11 volumes)− Hedged 2,210 Bbls/day for 1st quarter of 2012

0

2,000

4,000

6,000

2011 2012 2013

$84.28

$96.54

$102.05

Capital Expenditures

$0

$200,000

$400,000

$600,000

$800,000

2006 2007 2008 2009 2010 2011 Budget

Unit Petroleum Unit Drilling Superior Pipeline

(In Thousands)

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 the factors discussed or referenced in the “Risk Factors” section of the Company’s Prospectus Supplement filed with the Securities and Exchange Commission (“SEC”) pursuant to Rule 424 (b), 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.