Unit Corp. · OTC:UNTC
Unit — Investor Day (December 2013)
153 slides from Unit's investor day presentation, Dec 4, 2013
Slide 1: Welcome to Unit Corporation's Investor Day
A Diversified Energy Company Welcome to Unit Corporation’s Investor Day December 4, 2013
Slide 2: Agenda – 2013 Investor Day
Agenda – 2013 Investor Day Company Overview Larry Pinkston Chief Executive Officer & President Midstream Review Bob Parks President, Superior Pipeline Company Contract Drilling Review John Cromling Executive Vice President, Drilling Oil and Natural Gas Review Brad Guidry Executive Vice Presi
Slide 3: Forward-Looking Statement
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 addres
Slide 4: Larry Pinkston
Larry Pinkston Chief Executive Officer and President 4
Slide 5: Overview of Operations
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 17 Casper Marcellus Tulsa Headquarters Arkoma Basin Anadarko 74 Basin Oklahoma Permia
Slide 6: Corporate Priorities
Corporate Priorities Drive shareholder value creation Build NAV and cash flows through repeatable and sustainable growth trajectory for our Oil and Natural Gas segment A Repositioning Contract Drilling segment to Diversified expand customer base Energy Company Maximize Midstream Segment cash
Slide 7: 2013 Accomplishments
2013 Accomplishments Oil and Natural Gas Segment Year to date production +22% and segment cash flow +14% Production guidance raised from initial 13-16% production growth to 15-18% Increased production growth despite lowering 2013 capital expenditures budget Contract Drilling Segment Aver
Slide 8: Capital Allocation Criteria
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 Refurbishmen
Slide 9: 2014 Operating Segment Capital Budget Estimate
2014 Operating Segment Capital Budget Estimate Key focus areas include: Expand drilling in Wilcox, Granite Wash and Mississippian plays Begin development of new Anadarko Basin oil play BOSS Rig development and deployment Improve and grow midstream cash flow Drive midstream contract shift
Slide 10: The Integrated Business Model
The Integrated Business Model Granite Wash Margin Example (Mcfe) (Mcfe) Petroleum Segment Net Cash Margin $3.69 Drilling Segment Uplift1 $0.30 24% Midstream Segment Uplift2 $0.60 Increase Unit Corporate Net Margin $4.59 Revenue per Mcfe $6.76 (Mcfe) F&D3 $1.46 Dry Gas $2.37 NGLs (C2+) $2.40 LOE / Pr
Slide 11: Midstream Segment
Midstream Segment Unit Oil and Natural Gas segment production growth is a natural contributor Volume Capture Plans New customers 2014 Theme – Increase New areas Cash Flow & ROR New Construction opportunities Scalable Repeatable: Extensions and expansions Average across all systems; 1
Slide 12: Contract Drilling Segment
Contract Drilling Segment Go to market strategy Prototype rig drills for our Oil and Natural Gas Segment Build it, Run it, Prove it, Perfect it, Market it The BOSS Focus on marketing to new customers Fleet Realignment Sold 5 Idle 2000-3000 HP rigs during 2013 Contracts pending on 5 add
Slide 13: Oil and Natural Gas Segment
Oil and Natural Gas Segment Spent the last couple years developing a focus on core areas Largest inventory of potential drilling locations in Long-Term Growth company history. Visibility Potential locations = solid growth Reserves Production EBITDA Preliminary 2014 Began 2013 with 6 ri
Slide 14: Superior Pipeline Company
A Diversified Energy Company Superior Pipeline Company 14
Slide 15: Bob Parks
Bob Parks President, Superior Pipeline Company 15
Slide 16: Agenda – Superior Pipeline Company
Agenda – Superior Pipeline Company Superior Defined Track Record Current Position Competitive Strengths Positioned for Growth Cashion Processing Plant Cashion, Oklahoma 16
Slide 17: Superior Defined
Superior Defined A wholly-owned subsidiary of
Slide 18: Superior Pipeline Company
Superior Pipeline Company Midstream company engaged in buying, selling, gathering, processing, compressing and treating natural gas Proven track record of developing green field projects Entrepreneurial culture Exceptional customer service Record of disciplined growth Bruceton Mills Pipeli
Slide 19: Superior Services
Superior Services Natural Gas Gathering and Compression Natural Gas Processing Natural Gas Treating Design Construction Operation Pittsburgh Mills Compressor Station, Pennsylvania 19
Slide 20: Superior's Track Record
Superior’s Track Record Hemphill Gas Processing Facility, Hemphill County, Texas 20
Slide 21: Superior Track Record
Superior Track Record Established in 1996 Acquired by Unit Corporation in July 2004 Wholly-owned subsidiary of Unit Corporation Corporate Headquarters in Tulsa, OK Currently Operating in Oklahoma, Texas, Kansas, Pennsylvania and West Virginia Bellmon Gas Processing Plant, Noble County, Okl
Slide 22: Superior Track Record
Superior Track Record 37% compound growth rate in assets since year-end 2004 Installed processing capacity of 345 MMcf per day at eight different locations Increased from 12 to over 140 employees since 2004 Cumulative Invested Capital Segment Operating Cash Flow 600 50 500 40 $ in millions $ i
Slide 23: Superior Track Record
Superior Track Record Contract Mix Based on Volume 2010 Current 2013 Commodity Commodity Fee Based 27% Fee Based Based Based 49% 51% 73% Contract Mix Based on Margin Fee 2010 Based Current 2013 15% Commodity Commodity Fee Based Based Based 85% 53% 47% 23
Slide 24: Superior Track Record
Superior Track Record Corporate Synergies Unit Petroleum Provides Project Development Opportunities Base Load New Systems 3rd Party Opportunities Example Kansas Mississippian Unit vs. 3rd Party Margin Contribution 2010 2013 Unit Unit 25% 3rd 32% 3rd Party Party 75% 68% 24
Slide 25: Superior's Current Position
Superior’s Current Position 25
Slide 26: Attractive Customer Base
Attractive Customer Base Representative Customer Base Miles of Pipe Throughput Volume 1,500 400,000 Mcf per day 300,000 1,000 Miles 200,000 500 100,000 0 0 26
Slide 27: Midstream Core Operations
Midstream Core Operations 1,250,000 Dedicated Acres Texas Panhandle Northern Oklahoma / Kansas 32,000 dedicated acres 1,100,000+ dedicated acres 135 MMcf/d processing capacity 198 MMcf/d processing capacity* 308 miles of gathering pipeline 501 miles of gathering pipeline Pittsburgh Mills Ren
Slide 28: Granite Wash Overview
Granite Wash Overview Granite Wash Assets High Growth Area with Strong Anticipated Drilling Activity Driven by Liquid Rich Production Existing Available Capacity Expansion Opportunities with Limited Capital Required 28
Slide 29: NOMWOHU Overview
NOMWOHU Overview Oklahoma and Kansas Stacked Play Assets First Mover in Area Serving Active Mississippian Independent Producers Including Range, Devon and Sandridge 6 Processing Current Woodford Activity Facilities and 120 MMcf/d Available Processing Capacity* Current Hunton Activity *Includes
Slide 30: Marcellus Overview
Marcellus Overview Marcellus Play Assets Brookfield Pipeline As an Early Entrant into Basin, Constructed Three Gathering Systems PENNSYLVANIA Pittsburgh Mills Planned Extension Pipeline Projects Well Developed Regulatory Filing and Bruceton Mills Permitting Expertise Pipeline WEST VIRGINIA 30
Slide 31: Superior's Competitive Strengths
Superior’s Competitive Strengths Hemphill Processing Facility, Hemphill County, Texas 31
Slide 32: Competitive Strengths
Competitive Strengths Scalable Project Strong Footprint in Core Long-Term Development Areas Commitment Approach Pittsburgh Mills Compressor Station, Pennsylvania 32
Slide 33: Competitive Strengths
Competitive Strengths Scalable Project Development Approach – Granite Wash Example Processing Capacity Volume Mcf/d 160,000 140,000 120,000 Mcf per day 100,000 80,000 60,000 40,000 20,000 0 2005 2006 2007 2008 2009 2010 2011 2012 2013 Original 5 Added 20 Added 50 Plant Added 45 Transfer & 20 MMcf/d
Slide 34: Positioned for Growth
Positioned for Growth ay [*
Slide 35: Positioned for Growth
Positioned for Growth Growth Through Existing Assets Growth Opportunities in New Basins Strong Core Asset Base in High Growth Actively Exploring Opportunities in: Areas Permian Existing Plant Capacity Provides Near Eaglebine Term Growth Opportunity with Limited Tuscaloosa Additional Capi
Slide 36: Midstream Summary
Midstream Summary Projected to End 2013 with a Record Segment Operating Cash Flow of $49 million NOMWOHU 42% Granite Wash 26% Marcellus 17% Assets Strategically Located in High Growth Plays Well diversified Asset and Contract Mix Moving Towards Fee Based Structure with Less Commodity Pri
Slide 37: Unit Drilling Company
A Diversified Energy Company Unit Drilling Company 37
Slide 38: John Cromling
John Cromling Executive Vice President, Drilling 38
Slide 39: Respected History, Transition to Market, Build a Rig for the Future
Respected History Transition to Market Build a Rig for the Future 39
Slide 40: Complete Drilling Contractor
Complete Drilling Contractor Drilling Experienced Operational Crews Support Success Rigs A drilling contractor is more than just rigs 40
Slide 41: Complete Drilling Contractor
Complete Drilling Contractor Operational Support Operations Management Engineering Rig Manufacturing Rig Fabrication Full Maintenance Support Facility Mechanical / Electrical / Structural Technicians Shops Spare Equipment HSE Support Human Resources Recruiting Training 41
Slide 42: Diverse Customer Base
Diverse Customer Base Mid to large independents most common Rigs fit operator’s desires Goal to increase market share with large independents and majors Representative Customer Base 42
Slide 43: Rig Fleet Snap Shot
Rig Fleet Snap Shot 400-700 HP 750-1,000 HP 1,200-1,700HP 2,000 HP >2,000 HP 31% 41% 32% 33% 80% 69% 20% 59% 67% 68% Sale Pending: 4 29 41 44 3 5 70% of Total Fleet % Utilized % Unutilized 43
Slide 44: Geographically Diverse
Geographically Diverse Current Operating Rigs Rocky Mountains Oklahoma/Texas/Gulf Coast Mississippi 9 Rigs Bakken 10 Rigs Marmaton 2 Rigs Anadarko Basin 5 Rigs Pinedale Anticline 6 Rigs Texas/Oklahoma Granite Wash 21 Rigs Permian 3 Rigs Barnett 1 Rig Play Operating Rigs Anadarko Basin 5 Bakken 10 Ba
Slide 45: Operating Rigs Breakdown
Operating Rigs Breakdown 32% 68% Mechanical Rigs Electric Rigs 45
Slide 46: Mechanical Rigs
Mechanical Rigs 60 mechanical rigs in fleet 21 presently operating Upgraded to meet operators needs Ideally suited for the market 46
Slide 47: Unit Rig #337
Unit Rig #337 SandRidge Energy rig of the year 2012 47
Slide 48: A rig is not one machine, but a combination of components
A rig is not one machine, but a combination of components Hoisting Fluid and handling rotating Mud Walking or Pumps skidding system Pipe handling Power system BOP handling 48
Slide 49: Rig Upgrades Return Value
Rig Upgrades Return Value Individual components can be replaced to: Meet the needs of an operator Increase the value of the rig Potential growth opportunities 48 Refurbishments Since 2009 = $90 MM (cost recaptured within contract term) 49
Slide 50: Improved Drilling Efficiencies
Improved Drilling Efficiencies Example - Pinedale Wells Spud to Total Depth 70 60 50 40 30 20 10 0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 YTD Days, Spud to TD 61 64 45 42 34 27 22 16 14 12.8 11.8 Wells/ Rig -Year 6 5 7 8 9 11 13 20 23 24 25 50
Slide 51: BOSS Rig Design
BOSS Rig Design Combine the best technological innovations into one rig Involve personnel from multiple levels and backgrounds Use personnel experience to decide what works and what does not Create a unique rig that meets the demands of today’s market 2012 made the decision to design a new A
Slide 52: Introducing the BOSS Rig
Introducing the BOSS Rig Mud Pumps Fluid handling Power Hoisting and rotating Pipe handling Walking system BOP handling 52
Slide 53: Faster Between Locations
Faster Between Locations Quick assembly substructure 32 truck loads not including drill string or camp Smaller lighter loads require less permits to move 53
Slide 54: Optimized for Pad Drilling
Optimized for Pad Drilling Bi-directional walking system allows drilling multiple wells per pad BOP handling system for faster and safer nipple up and down Racking capacity for 22,000’ of 5” to be left in mast while walking rig 54
Slide 55: Advanced Technology
Advanced Technology Variable frequency drives (VFD) increase accuracy and precision Automated driller improves control of drilling parameters Ideal for drilling today’s more complex wells 55
Slide 56: More Hydraulic Horsepower
More Hydraulic Horsepower 2 – 2,200 horsepower mud pumps 1,500 gallon per minute flow rate available with one pump Unique quintuplex design improves efficiencies for downhole directional tools 56
Slide 57: Smaller Environmental Footprint
Smaller Environmental Footprint Dual fuel capable engines reduce air pollution and diesel costs Integrated drip pans mitigate environmental impact Compact location footprint minimizes surface damage and construction cost 57
Slide 58: Projected Rig Move Savings
Projected Rig Move Savings Bakken Four Well Pad Example Projected Savings to Operator Estimated Projected Bakken 4 Well Pad Cycle Cost Category Amounts Operation Days Cranes $40,000 Rig up 3 Truck $24,000 Drill 18 Transportation Skid 0.33 Truck Permits $6,000 Drill 18 Rig Move Rate $40,000 Skid 0.33
Slide 59: Respected History, Transition to Market, Build a Rig for the Future
Respected History Transition to Market Build a Rig for the Future 60
Slide 60: Oil & Natural Gas
A Diversified Energy Company Oil & Natural Gas
Slide 61: Brad Guidry
Brad Guidry Executive Vice President, Exploration and Production 62
Slide 62: Key Points
KEY POINTS History versus Future Focused Confidence in our Core Plays Significant well inventory and future resource potential Experience to perform 63
Slide 63: Core Areas
Core Areas Mississippian Marmaton Granite Emerging Play Mid Continent Region Initial Well* Wash Granite Wash 45% Liquids 2008 (H) Marmaton 91% Liquids 2010 (H) Mississippian 72% Liquids 2012 (H) Wilcox Emerging Play 25-87% Liquids 2013 (H) Upper Texas Gulf Coast Region Wilcox 44% Liquids 2003 (V) *
Slide 64: 2014 Outlook
2014 Outlook 2014 Activity Upside Resource Potential Average 12 Rigs 1,600-2,100 Gross wells 125 net wells 73% Avg. WI $600 - $725 MM CapEx 564-726 Gross MMBoe 47% Liquids 2014 Forecasted Annual Annual Production Production 2014 Guidance 15-18% 20,000 15,000 MBOE 10,000 5,000 0 2010 20
Slide 65: 2014 Estimated Capital Expenditures
2014 Estimated Capital Expenditures Drilling CapEx Breakdown 93% in Core Plays Other 7% Marmaton 12% Granite Wash 31% Emerging Play 10% Wilcox Mississippian 20% 20% 66
Slide 66: Frank Young
Frank Young Senior Vice President, Operations 67
Slide 67: Granite Wash
A Diversified Energy Company Granite Wash Texas Panhandle
Slide 68: Granite Wash Impact
Granite Wash Impact 2014 Activity Upside Resource Potential 2-5 Rigs 800-1,000 wells 29 net wells 70% Avg. WI $174 MM well CapEx 2.1 – 2.7 Tcfe 45% Liquids Granite Wash Production 140,000 120,000 100,000 80,000 Mcfe/d 60,000 40,000 20,000 0 2010 2011 2012 2013 Est 2014 Est NGLs Oil Gas
Slide 69: Texas Panhandle Position
Texas Panhandle Position Area Highlights 47,500 Net Acres 80% HBP 1,250 Wells 75% Operated 70% Working Interest Buffalo Wallow Average Net Daily Prod 109 MMcfe/d 46% Liquids Potential Locations 800-1,000 70
Slide 70: Buffalo Wallow Type Log
Buffalo Wallow Type Log GR # of Locations/Zone RES Granite Wash “A" 12 Granite Wash “A-1” 33 Granite Wash “A-2” 72 Granite Wash “B” 71 Granite Wash “C” 51 Granite Wash “C-1” 68 Gross Thickness = 2,300 Feet Granite Wash “D” 70 Granite Wash “E” 61 Granite Wash “F” 49 Granite Wash “F-1” 54 Granite Wash
Slide 71: GW F1 Comparison
GW F1 Comparison 54 Buffalo Wallow Locations Buffalo Wallow Field Frye Ranch Field Unit Petroleum Linn Operating Carr #2 Huff 32 #7 IP’d 17 MMCFGPD & 400 BCPD Grs 112’ Grs 112’ GW “F-1” Net 80’ Net 76’ Resistivity = 30–40 Ohms Porosity = 10-12% Resistivity = 20-30 Ohms Porosity = 8-10% 72
Slide 72: Buffalo Wallow Type Log
Buffalo Wallow Type Log GR # of Locations/Zone RES Granite Wash “A" 12 Granite Wash “A-1” 33 Granite Wash “A-2” 72 Granite Wash “B” 71 Granite Wash “C” 51 Granite Wash “C-1” 68 Gross Thickness = 2,300 Feet Granite Wash “D” 70 Granite Wash “E” 61 Granite Wash “F” 49 Granite Wash “F-1” 54 Granite Wash
Slide 73: GW E Comparison
GW E Comparison 61 Buffalo Wallow Locations Buffalo Wallow Field NW Buffalo Wallow Field Unit Petroleum TRI EX Noah #0814P Abraham #1-46 Horizontal GW “E” Offset EUR ~ 4-5 BCFE Gas Shows Grs 81’ GW “E” Net 67’ Grs 85’ Net 75’ Resistivity = 30 Ohms Porosity = 10-11% Resistivity = 30 Ohms D-N Porosity
Slide 74: Buffalo Wallow Type Log
Buffalo Wallow Type Log GR # of Locations/Zone RES Granite Wash “A" 12 Granite Wash “A-1” 33 Granite Wash “A-2” 72 Granite Wash “B” 71 Granite Wash “C” 51 Granite Wash “C-1” 68 Gross Thickness = 2,300 Feet Granite Wash “D” 70 Granite Wash “E” 61 Granite Wash “F” 49 Granite Wash “F-1” 54 Granite Wash
Slide 75: GW C1 Comparison
GW C1 Comparison 68 Buffalo Wallow Locations Buffalo Wallow Field Mendota Field Unit Petroleum Unit Petroleum Carr #2 Mahler C1 IP’d 3.5 MMCFGPD & 1009 BCPD Grs 99’ Net 54’ Grs 174’ GW “C-1” Net 61’ Resistivity = 30–40 Ohms Porosity = 10-12% Resistivity = 30-40 Ohms Porosity = 10-12% 76
Slide 76: Buffalo Wallow Type Log
Buffalo Wallow Type Log GR # of Locations/Zone RES Granite Wash “A" 12 Granite Wash “A-1” 33 Granite Wash “A-2” 72 Granite Wash “B” 71 Granite Wash “C” 51 Granite Wash “C-1” 68 Gross Thickness = 2,300 Feet Granite Wash “D” 70 Granite Wash “E” 61 Granite Wash “F” 49 Granite Wash “F-1” 54 Granite Wash
Slide 77: GW B Comparison
GW B Comparison 71 Buffalo Wallow Locations Buffalo Wallow Field Buffalo Wallow Field Unit Petroleum Unit Petroleum Carr #2 Carr #13-13P Horizontal GW “B” Offset EUR ~6-7 Bcfe Grs 158’ GW “B” Grs 143’ Net 125’ Net 118’ Resistivity = 30-40 Ohms Porosity = 10-13% Resistivity = 30-40 Ohms Porosity = 10
Slide 78: Buffalo Wallow Type Log
Buffalo Wallow Type Log GR # of Locations/Zone RES Granite Wash “A" 12 Granite Wash “A-1” 33 Granite Wash “A-2” 72 Granite Wash “B” 71 Granite Wash “C” 51 Granite Wash “C-1” 68 Gross Thickness = 2,300 Feet Granite Wash “D” 70 Granite Wash “E” 61 Granite Wash “F” 49 Granite Wash “F-1” 54 Granite Wash
Slide 79: GW A2 Comparison
GW A2 Comparison 72 Buffalo Wallow Locations Buffalo Wallow Field Buffalo Wallow Field Unit Petroleum Unit Petroleum Carr #2 Meek #1 Horizontal GW “A2” Offset IP’d 20 MMCFGPD & 610 BOPD Grs 242’ GW “A2” Grs 191’ Net 210’ Net 157’ Resistivity = 30-40 Ohms Porosity = 10-13% Resistivity = 30-40 Ohms Po
Slide 80: Buffalo Wallow Type Log
Buffalo Wallow Type Log GR # of Locations/Zone RES Granite Wash “A" 12 Granite Wash “A-1” 33 Granite Wash “A-2” 72 Granite Wash “B” 71 Granite Wash “C” 51 Granite Wash “C-1” 68 Gross Thickness = 2,300 Feet Granite Wash “D” 70 Granite Wash “E” 61 Granite Wash “F” 49 Granite Wash “F-1” 54 Granite Wash
Slide 81: GW A1 Comparison
GW A1 Comparison 33 Buffalo Wallow Locations Buffalo Wallow Field Buffalo Wallow Field Unit Petroleum Unit Petroleum Carr #2 Hefley 13 #4 Horizontal GW “A1” Offset EUR ~ 5-6 Bcfe Grs 180’ GW “A1” Net 52’ Grs 188’ Net 53’ Resistivity = 20-40 Ohms Porosity = 10-12% Resistivity = 20-40 Ohms Porosity =
Slide 82: Granite Wash Historical Type Curve
Granite Wash Historical Type Curve Historical Monthly Production 1,000,000 _____Type Curve - - - - - Average Production* _____ Buffalo Wallow Wells Single Well Parameters 100,000 EUR: 3.8 BCFE MCFE Well Cost: $5.5 MM ROR: 41% 10,000 Payout: 1.9 Years GAS (SHRUNK) 1,000 EUR: 1.9 BCF 1 3 5
Slide 83: Granite Wash Drilling Optimization
Granite Wash Drilling Optimization 30% Decrease in Drilling Cost per Foot and Days to Rig Release Drilling Cost Per Foot Linear (Days) $1,200 60 $1,000 50 Drilling Cost Per Foot ($/ft) $800 40 Days $600 30 $400 20 $200 10 $0 0 2010 2011 2012 2013 Est. 2014 Est. • Information shown above excludes dat
Slide 84: Contiguous Acreage Advantages
Contiguous Acreage Advantages Pad Drilling and Completion Efficiencies 6-8 Wells per Pad $280,000 Cost Savings per Well Location Rig Mobilization Sequential Fracture Treatments Potential for Extended Laterals SWD Infrastructure Buffalo SWD Wells/Lines Service Multiple Producing Wells W
Slide 85: Granite Wash Cash Margin
Granite Wash Cash Margin (Mcfe) Net Cash Margin $3.69 Revenue per Mcfe $6.76 Dry Gas $2.37 Costs (Mcfe) NGLs (C2+) $2.40 Condensate $1.99 F&D1 $1.46 $6.76 LOE / Processing $0.82 Prod. Taxes $0.31 G&A $0.48 Total Costs $3.07 1. Drilling and completion costs 86
Slide 86: Granite Wash Impact and Key Takeaway Points
Granite Wash Impact 2014 Activity Upside Resource Potential 2-5 Rigs 800-1,000 wells 29 net wells 70% Avg. WI $174 MM well CapEx 2.1 – 2.7 Tcfe 45% Liquids Granite Wash Key Takeaway Points Cash margin and ROR are excellent in today’s commodity price environment because NGL and conden
Slide 87: Marmaton
A Diversified Energy Company Marmaton
Slide 88: Marmaton Impact
Marmaton Impact 2014 Activity Upside Resource Potential 2 Rigs 125-200 wells 25 net wells 70% Avg. WI $67 MM well CapEx 13-21 MMboe 91% Liquids Marmaton Production 6,000 4,000 Boe/d 2,000 0 2010 2011 2012 2013 est. 2014 est. NGLs Oil Gas 89
Slide 89: OK Panhandle Marmaton Position
OK Panhandle Marmaton Position Area Highlights Net Acres: ~ 120,000 55% HBP 140 HZ Wells 95% Operated 85% Working Interest Average Net Daily Prod 5,250 boe/d 91% Liquids Potential Locations 125-200 90
Slide 90: Marmaton Normalized Curve
Marmaton Normalized Curve Historical Monthly Production 100,000 _____Type Curve - - - - - Average Production* 10,000 Single Well Parameters EUR: 110 MBOE BOE 1,000 Well Costs: $2.8 MM (includes SWD allocation) ROR: 65% 100 Payout: 1.2 Years OIL 10 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31
Slide 91: Lower Marmaton Upside
Lower Marmaton Upside Patzkowsky D 1-30H McKinney 1-29H 96 MBOE EUR 175 MBOE EUR McKinney 1-29H Patzkowswky D 1-30H 92
Slide 92: Kansas City Lime Upside
Kansas City Lime Upside Wheeler Area Jameson Area Albert Area Excellent oil shows of florescence and Production Test Kansas City Lime: White Light Ultraviolet Light streaming cuts in samples 40 BPD Oil; 35 MCFD; 164 BBL Water Hydrocarbon show in core
Slide 93: Marmaton Drilling Optimization
Marmaton Drilling Optimization 30% Decrease in Drilling Cost per Foot and Days to Rig Release Drilling Cost Per Foot ($/ft) Linear (Days) 450 25 400 350 20 Drilling Cost Per Foot ($/ft) 300 15 250 Days 200 10 150 100 5 50 0 0 2010 2011 2012 2013 Est. 2014 Est. • Information shown above excludes data
Slide 94: Extended Lateral Advantages
Extended Lateral Advantages Decreases costs by ~ 25% 4,500’ Lateral - $2.8 MM 10,000’ Lateral - $4.2 MM Combination of lower costs and more oil recovery likely makes infill wells with long laterals economic to drill Decreases surface disturbance Fewer Locations & Roads Fewer Tank Batte
Slide 95: Marmaton Cash Margin
Marmaton Cash Margin (Boe) Net Cash Margin $48.71 Revenue per Boe $93.83 Dry Gas $2.35 Costs (Boe) NGLs (C2+) $6.62 Oil $84.86 F&D1 $26.88 $93.83 LOE / Processing $13.44 Prod. Taxes $1.70 G&A $3.10 Total Costs $45.12 1. Drilling and completion costs 96
Slide 96: Marmaton Impact and Key Takeaway Points
Marmaton Impact 2014 Activity Upside Resource Potential 2 Rigs 125-200 wells 25 net wells 70% Avg. WI $67 MM well CapEx 13-21 MMboe 91% Liquids Marmaton Key Takeaway Points Cash margin and ROR are excellent in today’s commodity price environment because oil comprises 80% of the wellh
Slide 97: Mississippian
A Diversified Energy Company Mississippian
Slide 98: Mississippian Impact
Mississippian Impact 2014 Activity Upside Resource Potential 2 Rigs 400-600 wells 38 net wells 80% Avg. WI $111 MM well CapEx 48-72 MMboe 72% Liquids Mississippian Production 2,500 2,000 Boe/d 1,500 1,000 500 0 2012 2013 Est 2014 Est NGLs Oil Gas 99
Slide 99: Kansas Mississippi Lime Position
Kansas Mississippi Lime Position Central Kansas Uplift Unit Core Leasehold Area Highlights Net Acres 140,000 $300-$350/acre 3-4 year term 9 Horizontal Wells 100% Operated 100% Working Interest Average Net Daily Prod 980 Boed 72% Liquids Potential Locations 400-600 100
Slide 100: Geologic Location Matters
Geologic Location Matters Central Kansas Unit’s core leasehold is in a Uplift large defined trap Thickness is 40’-70’ with porosity of 15-25% Hydrocarbon shows present from top to base of Miss Acreage focused in counties with high vertical production Shallow Reservoir depth Moderate wate
Slide 101: Unit Acreage in a Defined Trap
Unit Acreage in a Defined Trap A Unit’s Acreage Characteristics Good oil shows in vertical wells throughout acreage block A’ No oil shows in downdip wet chert Defined updip fault trap with vertical production adjacent to fault A Central KS Uplift Unit Acreage Downdip Waterleg A’ 1 ohm 1 ohm 20
Slide 102: Mississippian Well Data
Mississippian Well Data Actual Lateral Length vs Normalized Lateral Length of 4,300’ Actual Lateral Length Well Results Total 7 producing wells 3 wells = 80-90 % O&L 150 MBOE 3 wells = 45-70% O&L 1 well = 25-30% O&L Well Costs: $3.1 MM Normalized lateral length of 4,300’ Working Interest
Slide 103: Mississippian Drilling Optimization
Mississippian Drilling Optimization Decreasing Drilling Cost per Foot and Days to Rig Release Drilling Cost Per Foot ($/ft) Linear (Days) $600 25 $500 20 Drilling Cost Per Foot ($/ft) $400 15 Days $300 10 $200 5 $100 $0 0 2011 2012 2013 Est. 2014 Est.
Slide 104: Ongoing Optimizations
Ongoing Optimizations Omit 7” top set string- use 5 ½” long string Pad drilling Extended reach laterals Fracture Stimulation Optimization Well Spacing 105
Slide 105: Mississippian Impact and Key Takeaway Points
Mississippian Impact 2014 Activity Upside Resource Potential 2 Rigs 400-600 wells 38 net wells 80% Avg. WI $111 MM well CapEx 48-72 MMboe 72% Liquids Mississippian Key Takeaway Points Acreage position is largely contiguous with excellent term left Acreage position is in well define
Slide 106: Emerging Play
A Diversified Energy Company Emerging Play
Slide 107: Anadarko Basin Acreage Position
Anadarko Basin Acreage Position Area Highlights Net Acres: ~ 170,000 (>90% HBP) 2,600 Wells (~25% Operated) Net Avg. Daily Prod: 48 MMcfe/d (39% liquids) Emerging Play Highlights 2014 Activity 1-2 Rigs 12 net wells $58M well CapEx 108
Slide 108: Emerging Play – Anadarko Basin
Emerging Play – Anadarko Basin Zone A Zone A Zone B Zone C EUR 5.1 Bcfe 364 MBOE 6.0 Bcfe % Liquids 35% 87% ~25% Total Well Cost $4.3M $7.0M $9.0M # of Locations ~75 ~25 ~75 WI Range 40-90% 40-90% 40-90% Zone B Zone C 109
Slide 109: Emerging Play Key Takeaway Points
Emerging Play Key Takeaway Points Potential for five to seven stacked pays in play area Three zones successfully drilled horizontally to date Mix of oil and liquids rich gas zones Current well inventory of 150 to 175 locations Increasing leasehold position 110
Slide 110: Wilcox
A Diversified Energy Company Wilcox SE Texas
Slide 111: Wilcox
Wilcox 2014 Activity Upside Resource Potential 2-3 Rigs 75-100 wells 16 net wells (4 horizontal) 95% Avg. WI $112 MM well CapEx 450 - 500 Bcfe 44% Liquids Wilcox Net Production 70,000 60,000 50,000 40,000 MCFED 30,000 20,000 10,000 0 2010 2011 2012 est 2013 est 2014 NGLs Oil Natural Ga
Slide 112: Southeast Texas Program
Southeast Texas Program TYPE LOG 8,000’ JAZZ Area Newton Area Upper Wilcox 25,000 net acres 28,000 net acres 10,500’ 8 Middle Wilcox 12,500’ Basal 494 mi.² Wilcox 15,000’ UPC Jazz Field Discoveries U. & M. Wilcox ~ 200 Bcfe EUR 203 mi.² 113
Slide 113: Jazz Area
Jazz Area Gilly extended the basal Wilcox productive section 8,000’ 10,500’ 12,500’ Basal Wilcox Fairway 15,000’ 114
Slide 114: Gilly Field Development
Gilly Field Development Productive Area = 1,200 Acres Resource Potential = 302 Bcfe gross, 220 Bcfe net Epstein # 1 A’ Epstein # 5 A Productive in Basal Wilcox Section Continuing development 2013/2014 115
Slide 115: Gilly Field Strike Cross Section
Gilly Field Strike Cross Section Basal Wilcox Sands A A’ Total Volumetric Resource Potential - 302 Gross Bcfe - 220 Net Bcfe Holly Grove #1 Allar GU #1 Parker GU #2 Parker GU #1 Parker GU #3 Epstein #1 Epstein #2 Epstein #3 Epstein #4 Epstein #5 BS “O” 2026’ 1497’ 1219’ 2815’ 2474’ 1283’ 1306’ 1357’
Slide 116: Gilly Type Curve – Blackwood Sand
Gilly Type Curve – Blackwood Sand 100,000 EPSTEIN GU #1 EPSTEIN GU #2 Single Zone Parameters GILLY GU #1 EUR : 12.9 BCFE ( 41% Oil & MCFE/D AVERAGE 10,000 Liquids) Well Costs: $5.17 MM 990% ROR 5 Month Payout GAS EUR: 7.6 BCF IP (30 Day): 5.0 MMcf/d 1,000 Initial Decline: 5.5% 1 31 6
Slide 117: Gilly Field Net Production
Gilly Field Net Production Projected 49% Annual Growth in 2014 35,000 30,000 M 25,000 C F 20,000 E D 15,000 10,000 5,000 0 2011 2012 2013 EST 2014 EST NGLs Oil Natural Gas 118
Slide 118: Gilly Field Net Reserves
Gilly Field Net Reserves Transition to Proved Reserves 250 200 B C F 150 E 100 50 - 2011 2012 2013 Est 2014 Est Production & Proved Reserves Resource Potential 119
Slide 119: Newton Co. Wilcox +/- 28,000 Net Acres
Newton Co. Wilcox +/- 28,000 Net Acres 2 horizontal wells 2013 IP 30 ~ 900 Boed (80% liquids) 5 horizontal wells 2012-2013 IP 30 ~ 530 to 1,295 Boed (80% liquids) 120
Slide 120: 2014 Drilling Program
2014 Drilling Program 2014 Proposed wells Horizontal wells 121
Slide 121: Wilcox Gilly Well Margin
Wilcox Gilly Well Margin (Mcfe) Net Cash Margin $5.07 Revenue per Mcfe (Mcfe) $7.49 (Mcfe) F&D1 $0.53 Dry Gas $3.23 LOE $0.93 NGLs (C2+) $2.43 Condensate $1.83 Prod. Taxes $0.28 $7.49 G&A $0.48 Transportation $0.20 Total All Expense $2.42 1. Drilling and completion costs 122
Slide 122: Historical & Forecasted Wilcox Cash Flow
Historical & Forecasted Wilcox Cash Flow Proved Reserves Only CUM NET CASH FLOW CUM NET REVENUE CUM NET COSTS $1,200 ROR = 127% $1,000 $800 $600 $400 $200 $0 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 FUTURE 123
Slide 123: Wilcox Key Takeaway Points
Wilcox 2014 Activity Upside Resource Potential 2-3 Rigs 75-100 wells 16 net wells (4 horizontal) 95% Avg. WI $112 MM well CapEx 450 - 500 Bcfe 44% Liquids Wilcox Key Takeaway Points Historical Upper & Middle Wilcox has great results Basal Wilcox potential looks even stronger Upsi
Slide 124: Oil & Natural Gas Summary
A Diversified Energy Company Oil & Natural Gas Summary
Slide 125: 2014 Outlook Key Takeaway Points
2014 Outlook 2014 Activity Upside Resource Potential Ave. 12 Rigs 1600-2100 Gross wells 125 net wells 73% Avg. WI $600 - $725 MM CapEx 564-726 Gross MMBoe 47% Liquids Key Takeaway Points Focused Confidence in Core Plays Significant well inventory and resource potential Strong p
Slide 126: Financial Review
A Diversified Energy Company Financial Review 127
Slide 127: David Merrill
David Merrill Chief Financial Officer and Treasurer 128
Slide 128: Exercising Financial Discipline
Exercising Financial Discipline Committed to maintaining strong, stable capitalization with low financial leverage Flexible capital program to remain in-line with cash flows Planned and opportunistic monetization Use commodity hedges to protect cash flow 129
Slide 129: Debt Structure
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 None Maturity S
Slide 130: Liquidity for Financial Flexibility
Liquidity for Financial Flexibility Solid borrowing base Rig fleet upside liquidity No near-term maturities Debt Maturities $1,000 (in millions) $300 $500 $650 $500 $0 4Q-13 2Q-14 4Q-14 2Q-15 4Q-15 2Q-16 4Q-16 2Q-17 4Q-17 2Q-18 4Q-18 2Q-19 4Q-19 2Q-20 4Q-20 2Q-21 4Q-21 2Q-22 4Q-22 Undrawn Cred
Slide 131: Historical Credit Ratios
Historical Credit Ratios Total Debt / EBITDA EBITDA / Total Interest 1.1 1.1 102.5 1.2 120 97.5 1 100 66.5 0.8 80 0.5 60 38.4 0.6 0.4 0.3 40 21.1 0.4 13.0 0.1 20 0.2 0 0 2008 2009 2010 2011 2012 Sept. 2008 2009 2010 2011 2012 Sept. '13* '13* *12 months ended Sept. ‘13 Debt / Proved Reserves ($/Boe)
Slide 132: Strong Reserve Growth Position
Strong Reserve Growth Position 2012 Reserve Growth 170% 145% 120% 95% 70% 29% 45% 20% 9% Average -5% -30% UNT PDCE WLL XCO COG XEC BRY DVN DNR UPL AXAS NBL CHK OAS CLR EOG CRZO BBG FST ECA SWN REXX LINE ROSE EQT QEP PXD SM RRC SD APA NFX PQ APC CRK KOG AREX PVA -55% -80% Source: Bloomberg 133
Slide 133: Strong Reserve Replacement Position
Strong Reserve Replacement Position 2012 Reserve Replacement 1200% 900% 600% 337% 300% 182% Average 0% -300% UNT UPL PDCE DNR AXAS WLL XEC BRY DVN XCO FST OAS COG NBL BBG CLR LINE ROSE SM EOG NFX SWN CRZO EQT QEP PQ PXD CHK ECA REXX RRC SD APC APA CRK KOG AREX PVA -600% -900% -1200% Source: Bloomber
Slide 134: Strong Financial Position
0.0 X 1.0 X 2.0 X 3.0 X 4.0 X 5.0 X 6.0 X FST Source: Bloomberg XCO SD LINE CRK BBG PDCE UPL RRC ECA BRY CRZO CHK AXAS Strong Financial Position NFX DNR QEP REXX PVA EQT PQ KOG PXD Debt/2013 EBITDA DVN APC OAS CLR UNT 1.1x NBL APA SM WLL AREX SWN COG EOG 2.0x Average ROSE XEC 135
Slide 135: Conservative Reserve Position
Conservative Reserve Position 2012 Proved Developed Reserve Percentage 100% 90% 79% 80% 70% 58% Average 60% 50% 40% 30% 20% 10% 0% UNT UPL PDCE XCO XEC DVN FST WLL DNR BRY COG EOG AXAS NBL BBG SWN LINE ECA PQ PXD CHK SM NFX OAS CRZO CLR QEP EQT ROSE APC APA SD CRK RRC REXX KOG PVA AREX Source: Bloom
Slide 136: Finding Costs
Finding Costs All-In Finding Costs ($/Boe) $30 $20 $26.68 $23.73 $20.80 $10 $0 2010 2011 2012 137
Slide 137: Segment Contribution
Segment Contribution Adjusted EBITDA 2008 2013 Forecast 2014 Estimate 40% 4% 25% 6% 22% 7% 56% 69% 71% Oil and Natural Gas Contract Drilling Midstream (1) See appendix for adjusted EBITDA reconciliation. 138
Slide 138: Operating Segment Capital Expenditures
Operating Segment Capital Expenditures Operating Segment Capital Expenditures (excluding acquisitions) 2008 2013 Forecast 2014 Estimate 6% 13% 14% 8% 26% 8% 68% 79% 78% Oil and Natural Gas Contract Drilling Midstream 139
Slide 139: Planned and Opportunistic Monetization
Planned and Opportunistic Monetization Non-core asset sales 2011 - $10 million 2012 - $282 million 2013 YTD September - $90 million 2014 (Potential) - $100 million 140
Slide 140: Hedges
Hedges Target 50-70% of current year projected oil and natural gas production Natural Gas (MMBtu/d) Crude Oil (Bbls/d) 100,000 10,000 $3.63 80,000 8,000 $97.94 60,000 6,000 $93.85 40,000 4,000 $4.24 20,000 2,000 0 0 2013 2014 2013 2014 141
Slide 141: Larry Pinkston
Larry Pinkston Chief Executive Officer and President 142
Slide 142: Investment Considerations
Investment Considerations Oil and Natural Gas Segment We are in the plays not by default but rather due to the returns we can realize for our shareholders Long-term Growth Visibility Midstream Segment We have focused on converting more contracts to fee based Cash flow stabilization Cap
Slide 143: Questions & Answers
Questions & Answers 144
Slide 144: Thank you for attending Unit Corporation's Investor Day
A Diversified Energy Company Thank you for attending Unit Corporation’s Investor Day December 4, 2013
Slide 145: Appendix
Appendix 146
Slide 146: Appendix – Rig Fleet Growth 1995 - 2013
Appendix – Rig Fleet Growth 1995 - 2013 Purchased Hudson 9 Rigs, 140 Built 3 Rigs Built 6 Rigs, Purchased Lost 1 Rig 132 130 120 Sauer 9 Rigs, 129 127 127 Built 3 Rigs 121 122 117 Purchase 112 2008 100 Built 3 Rigs 2013 20 Rigs Purchased Built 1st 100 Cactus, 2 Strata Rigs, 2009 BOSS Rig & 80 Built
Slide 147: Appendix - Team Development
Appendix - Team Development Training Summary – YTD 3Q 2013 Topic # Personnel CPR/First Aid 410 Forklift 454 Manlift 35 Job Safety Analysis 225 Train the Trainer 22 3 Day Well Control 33 1 Day Well Control 46 Leadership 204 Harassment/Discrimination 204 Training Essentials 204 Teamwork 384 Hazard Rec
Slide 148: Appendix - Team Development
Appendix - Team Development Training Topic Positions Trained CPR/First Aid Forklift Aerial Lift Job Safety Analysis (JSA) Teamwork Hazard Recognition Fall Protection Basics of Rigging Top Drive Awareness Canrig Top Drive (2 day) BOSS Rig Training Hydraulics (1 day) Generator System Training Rig Mana
Slide 149: Appendix – High Capacity Fluid Processing
Appendix – High Capacity Fluid Processing Designed to handle high mud flow rates Capable of processing cuttings produced at high rates of penetration 150
Slide 150: Appendix – Built to Spec Blow Out Preventer
Appendix – Built to Spec Blow Out Preventer Stack design optimal for use with substructure Low height allows room for rotating control device Compact design allows for safe easy handling 151
Slide 151: Appendix - Customer Feedback
Appendix - Customer Feedback 8-27-2013 “I just want to let you know that the rig crews on Unit #326 did an exemplary job drilling the SHB 44-20 well and shattered the fastest well drilled in the Jonah field. This accomplishment was achieved by the hard work, . . .(pre-planning), and good communicati
Slide 152: Appendix - Customer Feedback
Appendix - Customer Feedback 9-30-2012 “This is extraordinary performance and I want to thank you guys, the consultants, pushers and crews at Unit 154 for your outstanding continuing efforts. There is no other way to say it - this is the best rig operating in the Texas Panhandle, bar none.” Max Whit
Slide 153: Non-GAAP Financial Measures – Adjusted EBITDA
Non-GAAP Financial Measures – Adjusted EBITDA Nine months ended Sept. 30, Years ended December 31, ($ in Millions) 2012 2013 2009 2010 2011 2012 Net Income $80 $133 ($56) $146 $196 $23 Income Taxes 51 84 (32) 91 123 16 Depreciation, Depletion and Amortization 234 243 177 205 281 319 Impairment of Oi