Unit Corporation - EnerCom, Inc.

EnerCom’s London Oil & Gas Conference
June 11, 2013

Overview of Operations
16
Bakken
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
Casper
Office
127 Unit Rigs
E&P Plays
18
77
Anadarko Basin
Oklahoma
Permian Basin
City Office
Mid-Stream Operations
Houston
Office
Tulsa
Headquarters
16
Arkoma Basin
Gulf Coast Basin
Marcellus
North La/
East Texas Basin
Integrated Business Approach
2

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 69% since 2003
– Sold 15 rigs since 2003
– 127 drilling rig fleet
• Mid-Stream
– 1,134% increase in natural gas processing volumes since 2004
– 902% increase in daily liquids sold volumes since 2004
– 1,373 miles of pipeline
• Strong Balance Sheet
– Remains conservatively financed as the company has grown
3
(1)
As of 12/31/2012.

Capital Allocation Criteria
Oil and Natural Gas Segment
Minimum 15% risk-adjusted ROR for new well proposals
Contract Drilling Segment
New build rigs – minimum contract term of 2 to 3 years at a day rate
sufficient 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 Segment
Minimum 25% risk-adjusted ROR for POP/POI projects
Minimum 15% risk-adjusted ROR for Fee Based projects
4

Core Upstream Producing Areas
Marmaton
Marmaton
Mississippian
Granite
Wash
Wilcox
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 Q1 2013 Daily Production
NGL
23%
NGL
20%
Oil
15%
Gas
62%
Oil
20%
Gas
60%
5
Proved Reserves: 150 MMBoe
Daily Production: 44.1 MBoe/d

Track Record of Reserve Growth
Proved Reserves (MMBoe)
160
150
2003 – 2012 CAGR: 15%
140
120
116
104
100
95 96
86
79
80
69
58
60
48
40
20
0
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Oil / NGLs
Natural Gas
Annual Reserve Replacement (1)
400%
337%
Minimum Target: 150%
300% 285%
261%
221%
202%
200%
186%
166% 171% 176%
164% (2)
100%
113%
0%
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
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
(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.
6

Increasing Production while
Improving Commodity Mix
Annual Production (MBoe/d)
50
40
39
45
44
33
30
29
28
27
20
10
28%
55%
0
2008 2009 2010 2011 2012 2013E
Net Wells
Drilled:
134
43
88 82
80
7
Oil / NGLs
Natural Gas
Production Range

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
• Current AFE CWC: $5.3 MM
• Estimated reserve range: 3.5 – 4.0 Bcfe
• Calculated ROR = 49% - 70% (Flat $90 oil, $30 NGL, $3.25 gas)
• First sales on 29 GW horizontal wells 2012
GW Type Log - Buffalo Wallow Field
11,000’ +/-200’
• 2012 30-day average IP = 4.1 MMcfe per day
• Production up 41% in 2012 over 2011
2013 ACTIVITY
• Q1 2013 = average net 88 MMcfe per day (46% oil & NGLs)
• Q1 – 4 wells completed – 30 day IP = 4.7 MMcfe per day
13,400’ +/-200’
• 4-6 Unit rigs: First sales on 30 gross wells
• Estimate capital expenditures $140 million net
• First Noble well spud in Q2
8

Marmaton Oil Play
Total 113,000 net acres in focus area (47% HBP)
HIGHLIGHTS
• Completed 95 operated horizontal wells since 2010
• 150 potential locations on 640 acre spacing
• Estimated reserve range: 120 - 130 MBoe per well
• Current AFE CWC: $2.7 million per well
• Calculated ROR 80% - 100% (Flat $90 oil, $30 NGL, $3.25 gas)
Focus
Area
• First sales on 32 horizontal wells (includes two extended
laterals) in 2012
• 30 day IP 391 Boe per day for 2012 wells
• Production up 61% in 2012 over 2011
2013 ACTIVITY
• Q1 2013 average net 4,148 Boe per day (92% oil & NGLs)
• Q1 – 10 wells completed – 30 day IP = 393 Boe per day
• Two Unit rigs (3 rd rig for 4 wells)
• Estimate first sales on 40 gross wells (includes 3 extended
laterals)
• Estimate capital expenditures $90 million net 9

Wilcox Liquids Play
WILCOX HIGHLIGHTS
“Gilly” Field
Discovery
• Completed 122 wells since 2003 with 73% success rate
• 72,000 net acres
“Gilly” Field Discovery – announced July 2012
• Total reserve potential = 168 Bcfe net (262 Bcfe gross)
Unit Prospect Area
• Eight Wilcox potential pay zones (4 zones currently
producing)
• Six “Gilly” Field producing wells
Average 255’ net potential pay/well
• Estimated AFE CWC: $5.4 million
“Gilly” Field Discovery
1,000 Acres
2013 ACTIVITY
• Q1 2013 = average net 35 Mmcfe per day (42% NGLs)
Completed wells
2013 wells
Future wells
• One - two Unit rigs in Wilcox
• 12 gross wells (includes 4 Gilly field vertical wells / 7 other
prospects / one horizontal well)
• Estimate capital expenditures $60 million net
10

Mississippian Play
Central Kansas Uplift
Total 110,000 net acres in focus area (5% HBP)
HIGHLIGHTS
• Approximately 300 potential locations (320 acre spacing)
• Average well depth +/- 8,000’ (includes 4,000’ lateral)
• Mississippian pay zone +/- 50’ thick
Mississippian Trend
2013 ACTIVITY
Focus Area
Initial Well
105,000 Net Acres
Mississippian Wells
• Drill 3 wells in Q1 – wait on pipeline infrastructure to be
built – estimate Q3 completion
• Resume drilling in Q3 with one Unit rig and anticipate
adding second rig in Q4
• First sales on 13 gross wells
• Estimated reserve range = 125 - 180 MBoe (92% oil & liquids)
• Calculated ROR 40% - 66% (Flat $90 oil, $30 NGL, $3.25 gas)
• Estimated AFE CWC: $3.0 million
2012
• Drilled 4 horizontal Miss wells in Kansas focus area
• Initial well completed May 2012; second well December
2012
• 30 day average IP 240 Boe per day (89% oil and liquids)
11
• Estimate capital expenditures $40 million net

Significant Drilling Presence in
Attractive Producing Regions
18
16
Casper
Office
77
Oklahoma
City Office
Tulsa
Headquarters
127 rig fleet
– Fleet average ~1,200 HP rating;
~16,724 ft depth capacity
– 97% of contracted rigs drilling horizontal wells
52% utilization rate for Q1 2013
– 69% of 45 1,200-1,700 HP rigs under contract
Refurbished / upgraded 19 rigs in 2011
and 15 rigs in 2012
2012 – placed 2 new build rigs into service (1,500 HP)
Contracted Rig
Commodity Mix
Geographical Location
127 Unit Rigs
16
Houston
Office
Dry Gas
1%
Liquids
Rich
99%
Rockies/
Bakken
27%
E. TX, LA
GC, S. TX
13%
Anadarko
Basin
60%
12
Note: Based on 65 contracted rigs. All charts represent total 127 rig fleet.

Margins / DayRates ($)
$20,000
90
Average Dayrates and Margins (1) 0
$15,000
$10,000
$5,000
60
30
Average Number of Rigs Utilized
$0
2009 2010 2011 2012 Q1 2013
Margins
Day Rates
Rigs Utilized
13
(1) Margins are before elimination of intercompany rig profit.

Diverse and Versatile Rig Fleet
0
400-700 h.p. 750-1,000 h.p. 1,200-1,700 h.p. 2,000 h.p. >2,500 h.p.
20%
Utilization
Percentage
(51% as of 6/4/13)
40%
60%
31 of 45
working
80%
100%
Number of Rigs: 31 38 45 7 71% 6
82 rigs equipped with integrated top drives
Average Depth Capacity: 16,724 feet
14

Introducing the New BOSS Drilling Rig
Optimized for Pad Drilling
• Multi-direction walking system
Faster Between Locations
• Quick assembly substructure
• 32 truck loads
More Hydraulic Horsepower
• (2) 2,200 horsepower mud pumps
• 1,500 gpm available with one pump
Environmentally Conscience
• Dual-fuel capable engines
• Compact location footprint
15

Mid-Stream Core Operations
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
• 168 MMcf/d processing capacity*
• 477 miles of gathering pipeline
• $34.5MM capital budget for 2013
Pittsburgh Mills
Hemphill
Reno
Bellmon
Central & Eastern OK
• 197,000+ dedicated acres
• 497 miles of gathering pipeline
• 1 processing facility with
12 MMcf/d processing capacity
• 2 treating facilities with
combined capacity of 190 GPM
Marcellus Shale
• 43,000 dedicated acres
• 23 miles of gathering pipeline
Segno
East Texas
• 41 Miles of gathering
pipeline
Processing facilities
Gathering systems
Indicates Company Headquarters in Tulsa, Oklahoma
Indicates Regional office in Pittsburgh, Pennsylvania
*Includes 28 MMcf/d from Reno, which will be operational in Q3
16

Historical Performance
Historical Daily Gathering Volumes (MMBtu / d)
NGLs Volumes (Bbl / d)
400,000
15,000
300,000
10,000
200,000
100,000
5,000
0
2009 2010 2011 2012 Q1 2012 Q1 2013
0
2009 2010 2011 2012 Q1 2012 Q1 2013
Contract Mix (Based on Volume) (1)
2012 Q1 2013
Contract Mix (Based on Operating Margin) (1)
2012 Q1 2013
POI
2%
POP
59%
Fee Based
39%
POP
52%
POI
2%
Fee Based
46%
POI
6%
POP
69%
Fee Based
25%
POI
6%
Fee Based
25%
POP
69%
17
(1)
POP represents percent of proceeds. POI represents percent of index.

Midstream Segment
2013 Outlook
• Mississippian Reno County, KS: 28 MMcf/d Cryogenic Plant
(Q3 2013)
• Mississippian Bellmon: 60 MMcf/d Cryogenic Plant (Q4 2013)
• Marcellus pipeline expansions
• 164 expected well connects in 2013
• Consistent growth through greenfield construction of pipelines
and processing plants in unconventional resource basins
18

Balance Sheet Summary
Total Assets 3,814.8 3,761.1
Long-Term Debt
3/31/13 12/31/12
(In Millions)
Senior Subordinated Notes 645.4 645.3
Bank Facility 70.0 71.1
Total Long-Term Debt 715.4 716.4
Shareholders’ Equity 2,010.0 1,974.3
Credit Line Undrawn 430.0 428.9
Long-Term Debt to
Total Capitalization 26% 27%
19

Debt Structure (1)
Senior Subordinated Notes
• $650 million, 6.625%
• 10-year, NC5; maturity 2021
Ratings S&P Moody’s Fitch
Corporate BB Ba3 BB
Senior Subordinated Notes BB- B1 BB-
Unsecured Bank Facility
• Borrowing Base
$800 million
• Elected Commitment
$500 million
• Outstanding
$70.0 million
• Maturity September 2016
20
(1) As of March 31, 2013

Hedges
Target 50–70% of current year projected oil and natural gas production
Natural Gas
Crude Oil
MMBtu/d
100,000
$3.67
Bbls/d
10,000
80,000
8,000
$97.94
60,000
40,000
$4.24
6,000
4,000
$91.16
20,000
2,000
0
2013 2014
0
2013 2014
21

Segment Contribution
Revenues ($ millions) Adjusted EBITDA ($ millions) (1)
$1,400
$1,315
$800
$1,200
$1,208
$602
$657
$1,000
$800
$707
$871
$600
$400
$373
$441
$600
$400
$319
$200
$148
$200
$0
2009 2010 2011 2012 Q1 2013
$0
2009 2010 2011 2012 Q1 2013
Oil and Natural Gas Contract Drilling Midstream
22
(1)
See appendix for adjusted EBITDA reconciliation.

Adjusted Earnings per Share (1)
$7.00
$6.00
$5.00
$4.00
$4.05 $4.16
$3.00
$2.00
$2.55
$3.08
$1.00
$1.12
$0.92
$0.00
2009(1) 2010 2011 2012(1)
Q1 2012 Q1 2013
23
(1)
See appendix for adjusted EPS reconciliation.

Capital Expenditures
(In Millions)
$1,500
$1,000
$500
$0
2008 2009 2010 2011 2012 2013 Budget
Oil and Natural Gas Contract Drilling Midstream Acquisitions
24

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 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.
25

Non-GAAP Financial Measures –
Adjusted EBITDA
Three months ended March 31,
($ in Millions) 2012 2013
2009 2010
Years ended December 31,
Net Income $52 $40
($56) $146
$196
$23
Income Taxes 33 25
(32) 91
123
16
Depreciation, Depletion and Amortization 79 77
177 205
281
319
Impairment of Oil and Natural Gas Properties - -
281 -
-
284
Interest Expense 2 4
1 -
4
14
(Gain) loss on unrealized value of commodity
derivatives (7) (2) (2) 1 2
(1)
Adjusted EBITDA $173 $148 $373 $441 $602 $657
2011
2012
Unit Petroleum
Income Before Income Taxes (1) $48 $59
($121) $176
Depreciation, Depletion and Amortization 52 52
115 119
Impairment of Oil and Natural Gas Properties - -
281 -
Adjusted EBITDA $100 $111
$275 $295
Unit Drilling
Income Before Income Taxes (1) $43 $24
$51 $60
Depreciation and Amortization 21 17
45 70
Adjusted EBITDA $64 $41
$96 $130
Superior Pipeline
Income Before Income Taxes (1) $5 $1
$5 $17
Depreciation and Amortization 5 7
16 15
Adjusted EBITDA $10 $8
$21 $32
$200
183
-
$383
$135
80
$215
$17
16
$33
($77)
211
284
$418
$159
81
$240
$6
24
$30
(1)
Does not include allocation of G&A expense.

Reconciliation of Adjusted Net Income
and Diluted Earnings Per Share
Three months ended March 31,
Years ended December 31,
($ in Millions) 2012 2013 2009 2010 2011 2012
Adjusted Net Income:
Net income $ 52.4 $ 40.2 $ (55.5) $ 146.4 $ 195.9 $ 23.2
Eliminate:
Unrealized value of commodity derivatives
gain (loss) (1.2) (4.3) (1.2) 0.6 1.5 (0.7)
Impairment of oil and natural gas properties - - (175.1) - - (176.6)
Adjusted net income $ 53.6 $ 44.5 $ 120.8 $ 145.8 $ 194.4 $ 200.5
Adjusted Diluted Earnings Per Share:
Diluted earnings per share $ 1.09 $ 0.83 $ (1.18) $ 3.09 $ 4.08 $ 0.48
Eliminate:
Unrealized value of commodity
derivatives gain (loss) (0.03) (0.09) (0.03) 0.01 0.03 (0.01)
Impairment of oil and natural gas properties - - (3.70) - - (3.67)
Adjusted diluted earnings per share $ 1.12 $ 0.92 $ 2.55 $ 3.08 $ 4.05 $ 4.16