barclay’s ceo energy- power conference · barclay’s ceo energy-power conference september 3,...

Barclay’s CEO Energy-Power Conference

September 3, 2014

Forward Looking Statement

2

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.

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

14

16Casper Casper

9

Arkoma Basin

Marcellus

North La/ East Texas Basin

Gulf Coast Basin

Houston Houston

Oklahoma City

Oklahoma City

Tulsa HeadquartersTulsa Headquarters

Anadarko Basin

Permian Basin

73

119 Unit Rigs

E&P Operations

Mid-Stream Operations

Office Location

7

3

Key Growth Points

4

Exploration & Production– 211% average production replacement since 2004– Liquids production has grown 162% since the end of 2009– Proved reserves: 160 MMBoe (1)

Drilling– Grown rig count 19% since 2004– Sold 24 rigs since 2009– 119 drilling rig fleet

Mid-Stream– 132% increase in daily natural gas processing volumes since 2009– 123% increase in daily liquids sold volumes since 2009– Approximately 1,500 miles of pipeline

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

(1) As of 12/31/2013.

First 6 Months YOY Accomplishments

5

Unit Corporation Revenue increased 20% Adjusted EBITDA increased 23% (1)

Oil and Natural Gas Segment• Year over year production increased 9%• Total liquids production up 17%

Contract Drilling Segment• Average per day operating margins, before elimination of intercompany

drilling rig profit and bad debt expense, increased 7%• Rigs utilized increased 7%• Six BOSS rigs under contract with 3rd party operators

Midstream Segment• Gas processed volume per day growth of 16%• Liquids sold volume per day growth of 59%

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

Capital Allocation Criteria

6

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 ratesufficient to provide a 100% cash on cash payout during a 3 year term

Rig Refurbishments – minimum contract term sufficient to provide a100% cash on cash payout during the initial term

Midstream Segment

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

Track Record ofReserve Growth

7

0%

100%

200%

300%

400%

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

0

20

40

60

80

100

120

140

160

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

(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

221% average annual reserve replacement over last 30 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

161%171% 176%202%

285%261%

221%186%

Minimum Target: 150%

164%(2)

116

160

5869

7986

95 96104

150

337%

113%

Increasing Production While Improving Commodity Mix

8

0

10

20

30

40

50

60

2009 2010 2011 2012 2013 2014E

Natural GasOil / NGLs Production Range

28

43

Annual Production (MBoe/d)

Net Wells Drilled:

27

33

39

88 82

46

80

13%-15%

91

Core UpstreamProducing Areas

9

41%

12%18%

17%11%

1%

Gas54%

Oil21%

NGL25%

Key focus areas include:

Mid-Continent:

– Granite Wash (Texas Panhandle)

– Hoxbar (Western Oklahoma)

– Marmaton (Oklahoma Panhandle)

– Mississippian (Kansas)

Gulf Coast:

− Wilcox (Southeast Texas)

Upside resource potential:

– 1,600 – 2,100 gross wells

– 73% average working interest

– 564 – 726 gross MMBoe

– 47% liquids

2014 CapEx Breakdown: $718 Million Budget Q2 2014 Daily Production: 50.7 MBoe/d

Granite Wash

MississippianWilcox

Hoxbar Play

MarmatonOther

Mississippian

Wilcox

SOHOT Play

Marmaton

Granite Wash

Mid Continent Region

Upper Gulf Coast Region

Granite Wash (Liquids)

10

Highlights:

Completed 93 operatedhorizontal wells since 2008

Average WI: 82%

Average IP30: 5.2 Mmcfe/d

45% liquids

2014 Activity:

5–6 rigs total (1-2 Buffalo Wallow)

35 gross wells

$250 million well CapEx

Single Well Parameters:

EUR: 3.8 Bcfe

Well Cost: $5.5 million

Upside Resource Potential:

800 – 1,000 wells

70% average WI

2.1 – 2.7 Tcfe

47,500 net acres47,500 net acres

Gross Thickness= 2,300 Feet

GW Type Log -Buffalo WallowField

Granite Wash “A"

Granite Wash “A-1”

Granite Wash “A-2”

Granite Wash “B”

Granite Wash “C”

Granite Wash “C-1”

Granite Wash “D”

Granite Wash “E”

Granite Wash “F”

Granite Wash “G”

Granite Wash “F-1”

12

33

72

71

51

68

7061

49

54

54

Potential Locations

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2010 2011 2012 2013 2014 Est

Mcf

e/d

NGLs Oil Gas

47,000net acres47,000

net acres

Hoxbar (Oil/Liquids)(SOHOT)

11

Highlights:

Potential for stacked pays in focus area

Mix of oil and liquids rich gas zones

13,100 net acres (Focus Area)

Current well inventory of 175 to 200 locations

Single Well Parameters:

Medrano Marchand

EUR: 3-4.5 Bcfe 300-500 MBoe

% liquids: 30%-40% 90%

Well cost: $4.2-$5.0 MM $6.5-$7.5 MM

2014 Activity:

3 rigs

13 gross operated wells


Focus Area

Marmaton (Oil)

12

116,000net acres116,000net acres

Highlights:

Completed 147 operatedhorizontal wells since 2010

Average WI: 83%

Average IP30: 340 Boe/d

91% liquids

2014 Activity:

2 rigs

35 – 40 gross operated wells


Single Well Parameters(Open Hole Completions):

EUR: 70 MBoe



75 – 150 wells

70% average WI

6 – 11 MMBoe

0

2,000

4,000

6,000

2010 2011 2012 2013 2014 Est

Boe

/d

NGLs Oil Gas

Upper Lansing/KC45’

Upper Marmaton

150’

Lower Marmaton100’

Gross Thickness= 365 Feet

Lower Lansing/KC70’

Mississippian (Oil)

13

0

200

400

600

800

1,000

1,200

1,400

2012 2013 2014 Est

Boe

/d

NGLs Oil Gas

140,000 net acres140,000 net acres

Highlights:

Total 20 producing wells since 2012

10 wells = >75% O&L

7 wells = 50-75% O&L

3 wells = <50% O&L

Working Interest: 98%

Average Well Cost: $3.1 million

Moderate water production (500 to 1,500 Bwpd)

Shoot 53-square mile 3-D in 2014

2014 Activity:

1 - 2 rigs

21 gross operated wells

$86 million well Cap Ex


400 – 600 wells

80% average WI

48 – 72 MMBoe

72% liquids

3D Area

Highlights:

Drilled 126 operated vertical wells since 2003

92% average WI

Historical ROR: 112%

2014 Activity:

2 rigs

15 gross wells



75 – 100 wells

95% average WI

450 – 500 Bcfe

44% liquids

Wilcox (Liquids)

14

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

2010 2011 2012 2013 2014 Est

MCFED

NGLs Oil Natural Gas

8

TYPE LOG

Upper Wilcox

Middle Wilcox

Basal Wilcox

8,000’

10,500’

12,500’

15,000’

JAZZ Area25,000 net acres

Gilly Field

Newton Area28,000 net acres

494 mi.²

203 mi.²

Blackwood “A” Sand

Gilly Field– Basal WilcoxBlackwood “A” Sand Parameters:

EUR: 12.3 Bcfe


ROR: 791%*

*Prices used: $3.95 gas, $96.01 oil, $45.77 NGLs

Gilly Field Development

15

16

Allar GU #1 Parker GU #2 Parker GU #1 Parker GU #3 Epstein #1 Epstein #2 Epstein #3 Epstein #4 Epstein #5 BS “O” #1

1497’ 1219’ 2815’ 2474’ 1283’ 1306’ 1357’ 1387’ 1249’

Resource 49 BCFE

Resource 40 BCFE

Resource 67 BCFE

Resource 130 BCFE

U. Gilcrease

L. Gilcrease

Blackwood

L. Blackwood

Resource 16 BCFEMagic

A A’

-13000

-14000

-15000

Gilly Field Strike Cross Section –Basal Wilcox Sands

Significant Drilling Presence in Attractive Producing Regions

17

119 Unit Rigs

HoustonOffice

TulsaHeadquarters

OklahomaCity Office

CasperOffice

14 119 rig fleet

– Fleet average ~1,100 HP rating;

– Almost all of contracted rigs drilling horizontal wells

62% utilization rate for Q2 2014

– 88% of 49 1,200-2,000 HP rigs under contract

Refurbished 48 rigs since 2009

Six BOSS rigs contracted

Contracted Rig

Commodity MixGeographical Location

Liquids Rich 99%

Dry Gas1%

AnadarkoBasin60%

E. TX, LAGC, S. TXPermian

14%

Rockies/Bakken

26%

Note: Based on 81 contracted rigs. All charts represent total 119 rig fleet.

16

7

73

9

Average Dayratesand Margins (1)

18

0

30

60

90

$0

$5,000

$10,000

$15,000

$20,000

2010 2011 2012 2013 6 mos. '14Margins Dayrates Rigs Utilized

(1) Margins are before elimination of intercompany rig profit and bad debt expense.

Mar

gin

s /

Day

Rat

es($

)A

verage Nu

mber of R

igs Utilized

Rig Fleet Snap Shot

19

88%

12%

1,200‐2,000HP

35%65%

≤700 HP 4,000 HP

4926 43 1

% Utilized % Unutilized

86 rigs equipped with integrated top drives

100%65%35%

750‐1,000 HP

77% of Total Fleet

Introducing the NewBOSS Drilling Rig

20

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 Conscious Dual-fuel capable engines Compact location footprint

Six BOSS Rigs Currently Contracted

Midstream Core Operations

21

Texas Panhandle32,000 dedicated acres135 MMcf/d processing capacity318 miles of gathering pipeline

Northern Oklahoma / Kansas1,200,000+ dedicated acres188 MMcf/d processing capacity534 miles of gathering pipeline

Marcellus 43,000 dedicated acres 33 miles of gathering pipeline

Central & Eastern Oklahoma70,000+ dedicated acres12 MMcf/d processing capacity540 miles of gathering pipeline

East Texas55 Miles of gathering pipeline

Indicates Company Headquarters in Tulsa, Oklahoma

Indicates Regional office in Pittsburgh, Pennsylvania

Hemphill

Reno

Bellmon

Segno

Pittsburgh Mills

Processing facilities

Gathering systems

Panola

38 Active Gathering Systems

335 MMcf/d Processing Capacity

Three Natural Gas Treatment Plants

Approximately 1,500 Miles of Pipeline

Key Metrics

1,350,000 Dedicated Acres

Midstream SegmentGranite Wash Overview

22

High Growth Area with Strong Anticipated Drilling Activity Driven by Liquid Rich Production

Existing Available Capacity

Expansion Opportunities with Limited Capital Required

Granite Wash Assets

Midstream SegmentHistorical Performance

23

– 37% compound growth rate in assets since year-end 2004

– Installed processing capacity of 335 MMcf per day at eight different locations

– Increased from 12 to over 145 employees since 2004

0

100

200

300

400

500

600

$ in

mill

ions

Cumulative Invested Capital

0

10

20

30

40

50

$ in

mill

ions

Segment Operating Cash Flow

Midstream SegmentContract Mix

24

Contract Mix Based on Margin

Contract Mix Based on Volume

30%

Unit vs. 3rd Party Margin Contribution

2010 Q2 2014

Fee BasedCommodity Based

70%

47%

51%

15%

53%

49%

85%

Fee BasedCommodity Based

3rd PartyUnit

25% 32%68%75%

Balance Sheet Summary

25

Total Assets 4,277.7 4,022.4

Long-Term DebtSenior Subordinated Notes 645.9 645.7Bank Facility

Total Long-Term Debt 645.9 645.7

Shareholders’ Equity 2,294.7 2,173.4

Credit Line Undrawn 500.0 500.0

Long-Term Debt toTotal Capitalization 22% 23%

(In Millions)

6/30/14 12/31/13

Segment Contribution

26

Oil and Natural Gas Contract Drilling Midstream

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

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

2010 2011 2012 2013 6 mos. '14$0

$200

$400

$600

$800

2010 2011 2012 2013 6 mos. '14

$1,352

$793$871

$1,208

$1,315

$391$441

$602

$657 $657

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

Capital Expenditures

27

$0

$500

$1,000

$1,500

2010 2011 2012 2013 2014 Budget

Oil and Natural Gas Contract Drilling Midstream Acquisitions

(In Millions)

Current Debt Structure

28

Senior Subordinated Notes $650 million, 6.625%

10-year, NC5; maturity 2021

Unsecured Bank Facility Current Borrowing Base $900 million

Elected Commitment $500 million

Outstanding (1) None

Maturity September 2016

(1) As of June 2014

APPENDIX

29

Non-GAAP Financial Measures – Adjusted EBITDA

30(1) Does not include allocation of G&A expense.

Years ended December 31,

($ in Millions) 2014 2010

Net Income $111 $146Income Taxes 70 91Depreciation, Depletion and Amortization 191 205Impairment of Oil and Natural Gas Properties - -Interest Expense 8 -

Unit Petroleum

Income Before Income Taxes (1) $171 $176Depreciation, Depletion and Amortization 131 119Impairment of Oil and Natural Gas Properties - -

Adjusted EBITDA $302 $295

Unit Drilling

Income Before Income Taxes (1) $52 $60Depreciation and Amortization 39 70


Superior Pipeline

Income Before Income Taxes (1) $6 $17Depreciation and Amortization 20 15


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

29 (1) (2) 1

Adjusted EBITDA $391 $441 $602 $657

(18) - - -

2013

$185117334

-15

$239226

-$465

$9671

$167

$1133

$44

8

$657

(2)

2013

$9962

159-8

$123107

-$230

$4835

$83

$415

$19

(10)

$319

1

Six months ended June 30,

Hedges

31

0

2,000

4,000

6,000

8,000

10,000

2014 20150

20,000

40,000

60,000

80,000

100,000

2014

Natural GasMMBtu/d

Crude OilBbls/d

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

$94.02

$4.22

$95.00

Barclay’s CEO Energy-Power Conference

September 3, 2014

barclay’s ceo energy- power conference · barclay’s ceo energy-power conference september 3,...

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