Agenda 2014 Investor Day - PDF Free Download

Agenda 2014 Investor Day Company Overview Contract Drilling Review Midstream Review Oil and Natural Gas Review Financial Review Conclusions/Q&A Larry Pinkston Chief Executive Officer & President John Cromling Executive Vice President, Drilling Bob Parks President, Superior Pipeline Company Brad Guidry Executive Vice President, Exploration & Production Frank Young Senior Vice President, Exploration & Production David Merrill Chief Financial Officer & Treasurer Larry Pinkston Chief Executive Officer & President 2

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 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. 3

Larry Pinkston Chief Executive Officer and President 4

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 120 Unit Rigs E&P Plays 14 Casper Mid Stream Operations Office Location 16 Anadarko Basin Permian Basin 9 72 Oklahoma City Tulsa Headquarters Houston Arkoma Basin 9 Gulf Coast Basin Marcellus North La/ East Texas Basin Pittsburgh 5

September YTD Comparisons Oil and Natural Gas Segment Production has increased 9% Liquids production (oil and NGLs) have increased 18% Contract Drilling Segment Average per day operating margins, before elimination of intercompany drilling rig profit, increased 7% Averaged 73.5 working rigs compared to 65.0, up 13% BOSS drilling rig program well underway First three currently working with fourth to be delivered before year end. Five additional BOSS rigs contracted to be built Ordered long lead time components for three additional BOSS rigs Midstream Segment Gas processed volume per day growth of 16% Per day liquids sold growth of 48% Segment operating profit increased 24% 6

Corporate Priorities Drive Shareholder Value Creation September YTD Comparisons Net Income 34% EBITDA (1) 26% EPS (diluted) 33% Debt to market capitalization (at September 2014) at 22%. Financially sound, well positioned to take advantage of opportunities 1) See Appendix for EBITDA reconciliation. 7

Oil and Natural Gas Segment Portfolio Approach Assets that add value in various commodity price environments SOHOT (Southern Oklahoma Hoxbar Oil Trend) Wilcox Granite Wash volume driver High Grading Opportunities Maintain Capital Discipline minimum of 15% riskadjusted rate of return Low PUD percentage Other Projects acreage positions held by production 8

Contract Drilling Segment Versatile Fleet Meeting Operator Needs Rig Modifications = Contract term Rationalizing Fleet Opportunistically BOSS Drilling Rig Grow Market Share Long Term Contracts Additional BOSS Drilling Rigs Dependent on Contracts 9

Midstream Segment Positioned for Growth Continued Focus on Fee Based Contracts Greenfield / Scalable Projects Core Competency New and Potential Projects Marcellus Fee Based Gathering 10

The Integrated Business Model Granite Wash Margin Example (Mcfe) (Mcfe) Petroleum Segment Net Cash Margin $1.72 Drilling Segment Uplift 1 $0.17 Midstream Segment Uplift 2 $0.43 35% Uplift Revenue per Mcfe (Per Price Deck*) $5.35 % of Revenue Stream Dry Gas 35% NGLs (C2+) 32% Oil 33% Unit Corporate Net Margin $2.32 Costs (Mcfe) F&D 3 $2.03 Operating Costs $0.92 Prod. Taxes $0.21 G&A $0.47 Total Costs $3.63 *Price deck with differentials applied: Oil $82.84, NGLs $28.26, Natural Gas $3.71 1. Intercompany margin applied to full cost pool/mcfe on average EUR 2. Gas processing margin Hemphill/produced Mcfe (Nat. gas and NGL stream only) 3. Drilling and completion costs 11

The Integrated Business Model Gilly Field Blackwood A Margin Example (Mcfe) (Mcfe) Petroleum Segment Net Cash Margin $2.46 Drilling Segment Uplift 1 $0.02 Midstream Segment Uplift 2 $0.15 7% Uplift Revenue per Mcfe (Per Price Deck*) $4.93 % of Revenue Stream Dry Gas 46% NGLs (C2+) 20% Oil 34% Unit Corporate Net Margin $2.63 Costs (Mcfe) F&D 3 $0.76 Operating Costs $0.91 Prod. Taxes $0.12 G&A $0.48 Transportation $0.20 Total Costs $2.47 *Price deck with differentials applied: Oil $83.84, NGLs $21.26, Natural Gas $3.74 1. Intercompany margin applied to full cost pool/mcfe on average EUR 2. Gas gathering margin 3. Drilling and completion costs 12

2015 Capital Expenditure Budget To Be Determined 13

Unit Drilling Company

John Cromling Executive Vice President, Drilling 15

A Versatile Drilling Company Future Current Historic 16

Simple Beginning Started with 3 small mechanical rigs in 1963 17

Rig Construction During 1970 s Demand for fast moving rigs Competitive from 9,000 14,000 Unit met demand with several rigs 18

Rig Construction During the 2000 s Demand for 1500 HP SCR rigs Multi well pad capable Winterized Unit met demand with 26 rigs 19

Rig Construction During 2014 Demand for 1500 HP AC rigs has increased Research and preparation Designed and built the BOSS rig 20

History of Growth 140 120 100 80 60 40 20 1995 Present Purchased 81 rigs Built 36 rigs Sold 22 rigs 0 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 21

Diverse Customer Base Mid to large independents most common Rigs fit operator s desires Goal to increase market share with large independents and majors 22

Transforming Fleet Sold less marketable rigs during the past 5 years (15) 500 1000 HP (3) 2000 HP (4) 3000 HP 23

Rig Fleet Snap Shot Total Rigs Operating: 12 25 41 4 800 HP 800 1,000 HP 1,200 1700 HP 2,000 HP 60% 40% 36% 64% 13% 87% 100% % Utilized % Unutilized 24

Geographically Diverse Bakken Play # of Rigs Anadarko Basin 24 Bakken 13 Eagleford 1 Granite Wash 7 Louisiana 1 Marmaton 4 Mississippi 11 Permian 10 Pinedale Anticline 6 Texas(other) 1 Wilcox 4 Total 82 Pinedale Anticline Granite Wash Permian Marmaton Mississippian Anadarko Wilcox Eagleford Louisiana 25

Rigs Put Into Service By Type (Over Last Twelve Months) Rig Type Horsepower < 800 800 1200 1200 2000 Total AC 3 3 SCR 1 2 7 10 Mechanical 3 1 4 17 26

Moving Rigs to Meet Operator Demand Rocky Mountains 4 Rigs Oklahoma Texas Panhandle Oklahoma Texas Panhandle 7 Rigs Permian Eagleford 3 Rigs Permian East Texas 1 Rig Oklahoma 27

Refurbishments and Additional Equipment Walking/Skidding systems Automated Catwalks Power systems Dual fuel Top drives Fluid systems Mud pumps Solids control 28

The Journey How did we get from concept. to the BOSS? 29

The BOSS Rig Objectives Rig for today and tomorrow Safety by design Highly mobile Automation systems Environmentally responsible Minimize non productive time 30

The BOSS Drilling Rig Mud Pumps Fluid handling Power Hoisting and rotating Pipe handling Walking system BOP handling 31

BOSS Rig Video 32

Active BOSS Rigs Rig #401: Granite Wash / Permian Rig #402: Bakken Rig #403: Niobrara* Rig #404: Bakken *Presently being commissioned. 33

Contracted BOSS Rigs Rig #405: Woodford/Cana Rig #406: Niobrara Rig #407: Permian Rig #408: Permian Rig #409: Niobrara 34

BOSS Performance Moving: 32 34 loads not including drill pipe or mats Faster rig up: Location to location < 72 hours Walking: Between wells 8 to 12 hours 35

Mud Pumps 2200 HP Quintuplex Able to drill with one pump Fulfills volume and pressure requirements Increased penetration rates 36

Mud Systems 7500 psi system: Allows for added pressure requirements of down hole tools Solids Control Equipment: High capacity matched to output of pumps 37

Training System Greatest concern to operators How will you crew the rig? How will you train the crews? 38

BOSS Training 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) Hydraulics (1 day) Generator System Training Air System Training Dual Fuel System Training VFD House / Sensor Training Drawworks Training Crown Alert Training BOP Accumulator Training BOSS Rig Training Training Topics BOP Stack Training BOP Handling Equipment Training Mud Pump Training P Quip Training Mud Pit System Training Hydraulic Catwalk Training Hoists Training Leadership Harassment / Discrimination Training Essentials for Supervisors Well Control (1 day) Pipe Handling (NOV ST 100) Hydraulics (3 day) Drill Line Ton Mile Horizontal Drilling Omron Driller's Controls Canrig Top Drive 39

What s Next for the BOSS? Continue to reduce weight of loads Continue to simplify rig up Be open to new technology 40

Closing Our 50+ year history is filled with examples of our VERSATILITY The BOSS rig is not the end. It is a milestone in our quest to be VERSATILE and meet the needs of the industry. We look forward to the next phase of our evolution and growth 41

Superior Pipeline Company

Bob Parks President, Superior Pipeline Company 43

Superior Pipeline Company Agenda Company Background Competitive Strengths Segment Metrics Core Assets Growth Opportunities Midstream Summary Granite Wash Processing Plant (Hemphill) 44

Background 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 Minco Gas Plant 45

Background Full Service Midstream Company Providing Processing, Gathering, Compression, Treating and Marketing Services Established Track Record of Developing Green Field, Scalable Projects Promote Entrepreneurial Culture Reputation for Providing Outstanding Customer Service Consistent 18 Year Growth Record 46

Competitive Strengths 47

Competitive Strengths Exceptional Working Relationship with Small and Large Producers Experienced Responsive Industry Reputation Staged and Scalable Project Development Approach Established Presence in Core Areas Focused on Long Term Commitment 48

Competitive Strengths Scalable Project Development Approach Hemphill Example 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000 0 2005 Original 5 & 20 MMcf/d Plant 2006 2007 2008 Added 20 MMcf/d Plant Processing Capacity 2009 2010 Added 45 MMcf/d Plant 2011 Plant Upgrades Increasing Capacity 2012 Added 45 MMcf/d Plant Volume MMcf/d 2013 Transfer Original Plants to Reno 2014 Connecting Buffalo Wallow Jan. 1 2015 Process Buffalo Wallow Production at Hemphill Total Processing Capacity: 135 MMcf/d Jan 2015: Ability to Process Buffalo Wallow Gas at Hemphill Capability to Scale Processing Capacity as Needed 49

Segment Metrics 50

Segment Metrics 34% compound growth rate in assets since year end 2004 Operating 14 processing plants at eight different locations with combined processing capacity of 335 MMcf/d Increased from 12 to 146 employees since 2004 700 Cumulative Invested Capital 80 Segment Operating Margin* $ in millions 600 500 400 300 200 100 $ in millions 60 40 20 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 est. 0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 *Before G&A est. 51

Segment Metrics Representative Customer Base Volume Growth (First 9 Months of 2014 vs. 2013) Cashion 29% Bellmon 37% Segno 51% Perkins 92% Reno 121% 52

Segment Metrics Current Contract Mix Based on Volume Current Contract Mix Based on Margin 2010 Current 2014 2010 Current 2014 51% 49% 68% 32% 15% 85% 44% 56% Commodity Based Fee Based 53

Segment Metrics Unit vs. Third Party Based on Margin 2010 2014 41% 59% 28% 72% Third Party Unit Corporate Synergies Project Development Opportunities Provided by Parent Company Base Load New Systems with Unit Production Established Presence Provides 3 rd Party Opportunities 54

Core Assets 55

Core Operations Texas Panhandle 32,000 dedicated acres 135 MMcf/d processing capacity 318 miles of gathering pipeline Northern Oklahoma and Kansas 1,750,000+ dedicated acres 188 MMcf/d processing capacity 551 miles of gathering pipeline Pittsburgh Regional office Pittsburgh Mills Hemphill Reno Bellmon Tulsa Headquarters Central & Eastern OK 52,000+ dedicated acres 12 MMcf/d processing capacity 540 miles of gathering pipeline Appalachia 60,000+ dedicated acres 33 miles of gathering pipeline Panola East Texas 55 Miles of gathering pipeline Segno Key Metrics 38 Active Systems Three Natural Gas Treatment Plants Approx. 1,500 miles of Pipeline Processing facilities Gathering systems 335 MMcf/d Processing Capacity 56

Granite Wash Highlights Connecting Buffalo Wallow Gathering System to Hemphill Processing Facility Operational January 2015 New Contract to Gather and Process Existing and New Buffalo Wallow Volume Additional Processing Capacity Available to Accommodate Future Growth at the Hemphill Facility Key Metrics 135 MMcf/d Total Processing Capacity 32,000 Dedicated Acres 9 mile Pipeline to Connect Buffalo Wallow to Hemphill 57

Northern Oklahoma and Kansas Stacked Play Highlights Early Entry into Area Established Position in North Central Oklahoma Stacked Plays Active 3 rd Party Customers Includes Range, Devon, Sandridge and various privatelyowned producers Implemented Staged Approach for Future Growth Stacked Plays Hunton Woodford Mississippian Key Metrics 1,750,000+ Dedicated Acres 6 Processing Facilities with 10 Processing Skids 188 MMcf/d Total Processing Capacity STACKED PLAY ASSETS 58

Appalachian Core Assets Early Entrant into Basin Expansion Project to Extend Pittsburgh Mills Gathering System Key Metrics 60,000+ Dedicated Acres 33 Miles of Large Capacity Gathering Pipeline Three Operational Gathering Systems 59

Appalachian Growth Opportunities Constructing Snowshoe Gathering System in Centre County, PA Estimated Total Capital: $97 million Initial 2015 Capital: $40 million Negotiating New Fee based Gathering Project in Butler County, PA Estimated Total Capital: $235 million Initial 2015 Capital: $150 million Negotiating Second Fee based Gathering Project in Butler County, PA Estimated Total Capital: $44 million Initial 2015 Capital: $30 million Continuing to Explore Power Generation Conversion Opportunities 60

Growth Opportunities 61

Growth Opportunities Focused on Long Term Growth and Increasing Cash Flow Established Asset Base in Growth Areas Available Plant Capacity for Future Growth Expand into Non-core Areas: Permian Eaglebine Tuscaloosa Expand Existing Systems into New Areas Apply Staged Scalable Development Approach 62

Midstream Summary Strong Core Asset Base Diversified Asset and Contract Mix Moving Towards Fee Based Structure Record Estimated Segment Operating Margin before G&A of $69 million North Central Oklahoma Stacked Play 52% Granite Wash 22% Marcellus 13% Scalable Development Approach Expansion Into New Basins Parent Company Relationship 63

Unit Petroleum Company

Brad Guidry Executive Vice President, Exploration and Production 65

Core Upstream Producing Areas Mid Continent Region Granite Wash Mississippian SOHOT Upper Gulf Coast Region Wilcox Key focus areas include: Mid Continent: Hoxbar (SOHOT Western Oklahoma) Granite Wash (Texas Panhandle) Mississippian (Kansas) Gulf Coast: Wilcox (Southeast Texas) 66

2015 Outlook 2015 Activity Average 7 8 Rigs 50 88 wells Upside resource potential: 1,400 1,800 gross wells 75% average working interest 760 960 gross MMBoe 47% liquids (16% oil, 31% NGLs) 20,000 Annual Production 15,000 Boe/d 10,000 5,000 0 2010 2011 2012 2013 2014 est. NGLs Oil Gas Prod Range 67

Wilcox

Wilcox Southeast Texas 2015 Activity 2 Rigs 12 15 wells (8 horizontal) 15,000 Gross Upside Resource Potential 135 wells (110 horizontal) 145 MMboe 95% Avg. WI 43% Liquids (11% oil, 32% NGLs) Wilcox Net Production Boe/d 10,000 5,000 0 2010 2011 2012 2013 2014 est. 2015 est. NGLs Oil Gas 69

Unit Petroleum Southeast Texas Wilcox Programs POLK TYLER JASPER NEWTON 3D AREA 494 mi.² HARDIN 3D AREA 203 mi.² Prior Years Drilling 2014 Drilling Program 2015 Drilling Program Southeast Texas Jazz Wilcox Area Newton County Program 70

Southeast Texas Newton County Program JASPER NEWTON TYPE LOG 11,500 Newton Area 28,000 net acres Upper Wilcox 13,400 Middle Wilcox 8 Foley Tram #1 30 Day IP 480 MCF 178 BO 234 BW Prior Years Drilling 2014 Drilling Program 2015 Drilling Program 3D AREA 203 mi.² 71

Southeast Texas Wilcox Program Jazz Area POLK UPC Wilcox Area 28,800 net acres TYLER Unit s Wilcox Discoveries 2003 to present Gross Cumulative Production = 23 MMboe Gross Remaining Proved Reserves = 39 MMboe Historical Finding cost $10.59 /Boe Historical ROR 112% TYPE LOG 8,000 Gilly Field 3D AREA 494 mi.² Upper Wilcox HARDIN 10,500 Middle Wilcox 8 Prior Years Drilling 2014 Drilling Program 2015 Drilling Program 12,500 Basal Wilcox 15,000 72

Wilcox 2014 Highlights and 2015 Activity 2014 Gilly Field production up 100% 2014 Gilly Field resource potential increased 33% Gilly Field potential upside Expansion from Gilly to adjacent fault blocks Horizontal and vertical resource potential Operational efficiencies 73

Gilly Field Gross Annual Production Projected 100% 2014 growth Only 2 new wells on line in 2014 through Q3 Current production rate at 10,200 boed 8,000 6,000 Boe/d 4,000 2,000 0 2011 2012 2013 2014 est. NGLs Oil Gas 74

Gilly Field Gilly Field (ytd September 2014) 12 PDP wells + 1 PUD (2 new wells in 2014) Average gross EUR per well = 2.6 MMboe A Producing Wells A Productive area 1,200 acres 2014 new well 75

Gilly Field Cross Section Daily Gross Production by Zone A Segno 3.6 miles A Untested U Gilchrease 1,200 Boed L Gilchrease Blackwood 1,770 Boed 7,272 Boed Commingling zones Producing Perforations Total Daily Production 10,243 Boed 76

Gilly Field Blackwood A Type Curve 90 Single Well (Zone) Parameters: EUR: 1.6 MMboe Well Costs: $5.3 MM ROR: 573% Payout: 6 months 40% Liquids OIL EUR: 125 MBbl IP (30 Day): 150 Bbl/d GAS EUR: 5.6 Bcf IP (30 Day): 6.0 MMcf/d NGL EUR: 485 MBbl IP (30 Day): 416 Bbl/d NGL Yield: 69 Bbls/MMcf Gas Shrink: 19% 77

Gilly Field Blackwood A Rates of Return 1000% 900% 800% 700% 600% Strip 500% 400% 300% 200% 100% 0% $70/$3.50/$24.50 $80/$3.50/$28.00 $90/$4.00/$31.50 $100/$4.00/$35.00 $100/$4.50/$35.00 $110/$4.50/$38.50 Management Strip see Appendix 78

Gilly Field Gross Reserves 80 Total Resource Potential (Q3) + 33% to 67.2 MMboe Proved Reserves (Q3) +190% to 26.8 MMboe 67.2 MMboe 60 50.9 MMboe MMBoe 40 39.5 MMboe 20 0 5.0 MMboe 2011 2012 2013 2014 est. Production Proven Remaining Resource Behind Pipe Unassigned Potential 16+ year reserve life @ current production 80

Gilly Field Gross Resource by Zone A 3.6 miles A Gross Resource Potential U Gilchrease 23.7 MMboe L Gilchrease Blackwood 13.7 MMboe 29.8 MMboe Total 67.2 MMboe Total 67.2 MMBoe 81

Gilly Field Lower Gilchrease Type Log 670 Boed 70 Single Well Parameters: EUR: 566 MBoe Well Costs: $5.3 MM ROR: 198% Payout: 12 months 41% Liquids Lower Gilchrease only (Mboe) 2014 2013 Gross Proved Reserves 7,600 0 Gross Resource Potential 6,100 11,200 Total Proved and Resource (gross) 13,700 11,200 +22% 82

Gilly Field Upper Gilchrease Type Log 1,200 Boed 150 Unstimulated Completion Flowing 5,400 psi Single Well Parameters: EUR: 744 MBoe Well Costs: $5.3 MM ROR: 331% Payout: 10 months Liquids 43% Upper Gilchrease only (Mboe) 2014 2013 Gross Proved Reserves 10,300 0 Gross Resource Potential 13,400 6,700 Total Proved and Resource(gross) 23,700 6,700 +254% 83

Gilly Field Expansion New Well Potential to expand field size by 25% to 1,500 acres Additions not currently in reserve estimates 2013 Field = 1,200 acres New well estimate completion in mid November Datum: Upper Gilchrease 85

Gilly Field Additional Upside Segno Series Sand A 3.6 miles A Segno Sand Segno U Gilchrease Gross Resource Potential Estimate 6 MMboe (not in current resource estimate) L Gilchrease Blackwood 86

Gilly North Field Development Gilly North productive area = 2,205 acres 1,400 acres 2014 exploratory wells 805 acres 88

Gilly Field North Gilchrease Type Log 70 Single Well Parameters: EUR: 297 MBoe Well Costs: $5.4 MM ROR: 23% Payout: 28 months 43% Liquids OIL EUR: 39 MBbl IP (30 Day): 74 Bbl/d GAS EUR: 1.2 Bcf IP (30 Day): 2.4 MMcf/d NGL EUR: 91 MBbl IP (30 Day): 175 Bbl/d NGL Yield: 73 Bbls/MMcf Gas Shrink: 20% 89

Gilly Field Area 2015 Development Productive Area Upthrown = 2208 Acres B Gilly North Gilly Field Gilly Downthrown B Prior Years Drilling 2015 Drilling Program 90

Gilly Field Dip Cross Section 2.7 miles B Prop Loc B Gilly North Gilly Field Gilly Downthrown Segno U Gilchrease 1700 L Gilchrease Blackwood 2200 91

Historical & Forecasted Wilcox Cash Flow Wilcox Cumulative Net Cash Flow (MM$) Proved Reserves Only ROR = 112% 93

Wilcox Horizontal Prospects Gross Resource Reserve Potential Average Average Total Vertical Completion Gross Resource Potential 2015 Depth Lateral D&C Cost History BOEPD Potential MMBOE Wells Wells AREA I 10,800 2,800 $117MM 508 15 18 1 AREA II 12,600 3,000 $135MM 718 20 18 2 AREA III 12,600 3,000 $105MM 712 12 14 1 AREA IV 10,400 3,000 $13MM 481 2 2 1 AREA V 12,700 3,000 $78MM 300 8 12 1 AREA VI 13,000 3,000 $39MM 153 4 6 0 AREA VII 11,900 3,000 $280MM 207 33 40 2 TOTALS $767MM 94 MMBoe 110 8 94

Wilcox Vertical Prospects Gross Resource Reserve Potential Vertical Type Per Well Resource Total Potential 2015 Depth Well D&C Cost Potential MMBoe D&C Cost Wells Drilling PROSPECT I 15,800 Wildcat $5.3MM 33 $64 MM 12 1 PROSPECT II 12,000 Wildcat $5.3MM 4 $16 MM 3 1 PROSPECT III 15,000 Development $5.3MM 2 $5 MM 1 1 PROSPECT IV 13,300 Development $5.1MM 1 $5 MM 1 1 PROSPECT V 16,000 Wildcat $5.3MM 7 $21 MM 4 0 PROSPECT VI 14,000 Wildcat $5.0MM 4 $20 MM 4 0 TOTALS 51 MMBoe $131 MM 25 4 95

Wilcox Resource Potential Summary Wilcox Horizontal Prospects Total Potential Potential 2015 D&C Cost MMBOE Wells Wells TOTALS $767 MM 94 110 8 Wilcox Vertical Prospects Total Potential 2015 D&C Cost Potential Wells Wells TOTALS $131 MM 51 25 4 Total Resource Potential Total Potential 2015 D&C Cost Potential Wells Wells TOTALS $898 MM 145 135 12 96

Gilly Field Drilling 300 Drilling Costs Improvement 45 250 40 35 Drilling Costs Per Foot ($/foot) 200 150 100 50 30 25 20 15 10 5 DAYS 0 2011 2012 2013 2014 YTD 2015 Estimate Cost per foot Days Spud to Rig Release 0 98

Lease Operating Expense $10.00 LOE Cost per BOE $9.00 24% reduction since 2011 $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2010 2011 2012 2013 2014 Est 99

Wilcox Gilly Well Margin (Actual through Q3) (Mcfe) Net Cash Margin $3.51 Revenue per Mcfe (3Q 2014 YTD) $5.98 Dry Gas 43% NGLs (C2+) 23% Condensate 34% (Mcfe) F&D 1 $0.76 Operating Costs $0.91 Prod. Taxes $0.12 G&A $0.48 Transportation $0.20 Total All Expense $2.47 1. Drilling and completion costs Average Realized Prices September 2014 YTD: Oil $99.88, NGLs $29.32, Natural Gas $4.33 100

Wilcox Key Takeaway Points 2015 Activity Gross Upside Resource Potential 2 Rigs 135 wells (110 horizontal) 12 15 wells (8 horizontal) 145 MMboe 95% Avg. WI 43% Liquids (11% oil, 32% NGLs) Wilcox Key Takeaway Points Competitive Advantage Historical full cycle Rate of Return of 112% Increased Gilly Field Resource Potential by 33% Additional upside Gilly expansion and Segno sands Horizontal and vertical upside Decreased drilling and LOE costs 101

Frank Young Senior Vice President, Exploration and Development 102

Anadarko Basin Southern Oklahoma Hoxbar Oil Trend (SOHOT)

Anadarko Basin Impact 2015 Activity 3 Rigs 18 23 wells Gross Upside Resource Potential (Hoxbar Only) 300 400 wells 150 205 MMBoe 60% Avg. WI 45% Liquids (27% Oil, 18% NGLs) 14,000 Anadarko Basin Production 12,000 10,000 Boe/d 8,000 6,000 4,000 2,000 0 2010 2011 2012 2013 2014 est. 2015 est. NGLs Oil Gas 104

Anadarko Basin Acreage Position Anadarko Basin Highlights: Net Acres: ~ 180,000 >90% HBP >2,600 Wells ~25% Operated Average Net Daily Prod 9,162 Boe/d 41% Liquids (26% Oil, 15% NGLs) SOHOT Highlights: 22 Horizontals Drilled 9 Operated 13 Non Operated SOHOT Core Average Net Daily Production 2627 Boe/d 76% Liquids (56% Oil, 20% NGLs) 105

SOHOT Stacked Pays 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000 10100 10200 10300 10400 10500 10600 10700 10800 10900 11000 11100 11200 11300 11400 11500 11600 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000 10100 10200 10300 10400 10500 10600 10700 10800 10900 11000 11100 11200 11300 11400 11500 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000 10100 10200 10300 10400 10500 10600 10700 10800 10900 11000 11100 11200 11300 11400 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000 10100 10200 10300 10400 10500 10600 10700 10800 10900 11000 11100 11200 11300 11400 8600 8700 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000 10100 10200 10300 10400 10500 10600 10700 10800 10900 11000 11100 11200 11300 8600 8700 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000 10100 10200 10300 10400 10500 10600 10700 10800 10900 11000 11100 11200 8200 8300 8400 8500 8600 8700 8800 8900 9000 9100 9200 9300 9400 9500 9600 9700 9800 9900 10000 10100 10200 10300 10400 10500 10600 10700 10800 900 MEDRANO MEDRANO MARCHAND MARCHAND CULP CULP W E WADE WADE HOXBAR 3,000 8W 7W 6N 5N W E 106

SOHOT: Medrano Sand (Hoxbar) Unit drilled discovery well in 2011 130 185 MMBOE gross resource potential 250 350 total locations (3 4 wells/section) 150 200 locations core area 100 150 extensional area 2 rig drilling program Well Cost: $4.9MM ~ 60% Avg. WI 33% liquids (8% oil, 25% NGLs) 11W 10W 9W 8W 7W 6W GR RES POR 7N Extensional Area Claiborne #1 4H Discovery 2011 9525 9500 9475 6N Cody 1 36H (2014) IP30: 240 bopd IP30: 3650 mcfpd 9600 9575 9550 100 9625 Core Area 9650 5N Medrano Horizontal Producer Medrano Vertical Producer Jobe 31 3H (2013) IP30: 390 bopd IP30: 5530 mcfpd Ezra Flowers 1 20H (2013) IP30: 40 bopd IP30: 4530 mcfpd 9675 9700 107

Medrano Historical Type Curve 10,000 Single Well Parameters: BOE / Day 1,000 EUR: 526 MBOE Well Costs: $4.9 MM ROR: 59% Payout: < 2 Years 100 100% 80% 60% 40% 20% 0% 1 31 61 91 121 151 181 211 241 271 301 331 361 391 Days Rates of Return (%) Strip $70/$3.50/$24.50 $80/$3.50/$28.00 $90/$4.00/$31.50 $100/$4.00/$35 $100/$4.50/$35 $110/$4.50/$38.50 Management Strip see Appendix OIL EUR: 38 MBO IP (30 Day): 75 BBL/D GAS (SHRUNK) EUR: 2,130 MMCF IP (30 Day): 3,840 MCF/D NGL EUR: 133 MBO IP (30 Day): 180 BBL/D NGL Yield: 2.1 gal/mcf 108

Medrano Net Cash Margin (Mcfe) Net Cash Margin $1.59 Revenue per Mcfe (3Q 2014 YTD) $4.87 Dry Gas 53% NGLs (C2+) 26% Oil 21% Costs (Mcfe) F&D $1.91 Operating Costs $0.58 Prod. Taxes $0.16 G&A $0.63 Total Costs $3.28 Average Realized Prices September 2014 YTD: Oil $96.48, NGLs $37.88, Natural Gas $4.20 109

900 11300 11200 10800 11200 11100 10700 11100 11000 11200 10600 11000 10900 11100 10500 10900 10800 11000 11000 11100 11200 11300 11400 11300 11100 11200 11300 11400 11500 11400 11200 11300 11400 11500 11600 10400 10800 10700 10900 10900 11000 11100 10300 10700 10600 10800 10800 10900 11000 10200 10600 10500 10700 10700 10800 10900 10100 10500 10400 10600 10600 10700 10800 10000 10400 10300 10500 10500 10600 10700 9900 10300 10200 10400 10400 10500 10600 9800 10200 10100 10300 10300 10400 10500 9700 10100 10000 10200 10200 10300 10400 9600 10000 9900 10100 10100 10200 10300 9500 9900 9800 10000 10000 10100 10200 9400 9800 9900 9700 9900 10000 10100 9300 9700 9800 9600 9800 9900 10000 9200 9600 9700 9500 9700 9800 9900 9400 9500 9000 9400 5N 9100 9700 9800 9600 9600 9500 MEDRANO 9300 9500 9600 9700 8900 9300 9400 8800 9200 9300 9100 8700 9000 9200 9300 9100 9300 9400 9200 9400 9500 6N 9200 9400 9500 9600 8600 9000 9100 8900 8500 8900 8800 8400 8800 8700 8300 8700 8800 8600 8800 8900 9000 9100 8900 8900 9000 9100 9200 9000 9000 9100 9200 9300 WADE 8200 8600 W CULP MARCHAND HOXBAR 3,000 SOHOT Stacked Pays E 8W 7W E W 110

SOHOT: Marchand Sand (Hoxbar) Very High ROR play (>400%) 16 21 MMBOE unrisked gross resource potential ~50 core locations 1 rig drilling program Well Cost: $7.0MM ~ 60% Avg. WI 89% liquids (80% oil, 9% NGLs) 11W 10W 9W 8W 7W 7N Extensional Area Allen 16 1H (2013) IP30: 780 bopd IP30: 700 mcfpd Rosey Havenstrite 1 30H (2014) IP30: 1210 bopd IP30: 610 mcfpd GR RES POR 11000 6N 11050 11025 100 Core Area 11075 5N Marchand Horizontal Producer Marchand Vertical Producer EOG: Jobe #1 31H (2014) IP30: 1696 bopd IP30: 1088 mcfpd GB Ranch 1 30H (2014) IP30: 1110 bopd IP30: 600 mcfpd 11100 111

Marchand Historical Type Curve 10,000 Single Well Parameters: BOE / Day 1,000 EUR: 440 MBOE Well Costs: $7.0 MM ROR: 410% Payout: < 1 Year 100 1 31 61 91 121 151 181 211 241 271 301 331 361 391 Days OIL EUR: 350 MBO IP (30 Day): 1,250 BBL/D 1000% 800% 600% Strip Rates of Return (%) GAS (SHRUNK) EUR: 280 MMCF IP (30 Day): 1,000 MCF/D 400% 200% 0% $70/$3.50/$24.50 $80/$3.50/$28.00 $90/$4.00/$31.50 $100/$4.00/$35 $100/$4.50/$35 $110/$4.50/$38.50 Management Strip see Appendix NGL EUR: 45 MBO IP (30 Day): 150 BBL/D NGL Yield: 5.5 gal/mcf 112

Marchand Net Cash Margin ($/Boe) Net Cash Margin $44.06 Revenue per Boe (3Q 2014 YTD) $76.33 Dry Gas 3% NGLs (C2+) 2% Oil 95% Costs ($/Boe) F&D $19.58 Operating Costs $6.68 Prod. Taxes $2.22 G&A $3.79 Total Costs $32.27 113

SOHOT Upside: Culp Sand (Hoxbar) Analogous to the Medrano play in thickness and geographical extent Proven vertical production 1 st test well : First half of 2015 11W 10W 9W 8W 7W 6W 7N Extensional Area GR RES POR 1 1 2 0 0 6N 1 1 2 5 0 100 1 1 3 0 0 5N Culp Vertical Producer 1 1 3 5 0 115

SOHOT Upside: Springer Shale CLR Discovery Wilkerson 1 20H IP: 2038 boepd CLR Confirmation Birt 1 13H IP: 793 boepd Identifying acres in Springer fairway 1 st well to be drilled in 2015 4 miles from CLR Wilkerson #1 20H CLR Springer EUR : 940 MBOE* CLR Reservoir Observations* High porosity & permeability Organic rich very siliceous rock Over pressured Great zone for stimulation GR RES POR Unit 2015 Springer Location Springer Fairway Horizontal Springer Shale 12750 12800 *From CLR Investor Presentation 2014 116

SOHOT Upside: Woodford Shale Identifying acres in Woodford fairway Acreage in gas window Determining economic viability in current price environment GR RES POR 13850 13900 Woodford Gas/Condensate Horizontal Woodford Shale 13950 14000 200 14050 117

Anadarko Basin Advantage PLAY 1 Gross acres: 10,000 (HBP) Average working interest: 36% Potential locations: 25 45 Current status: First well to be drilled Q4/2014 GR POR PLAY 2 Gross acres: 2,560 (HBP) Average working interest: 72% Potential locations: 10 30 Current status: Leasing additional acreage First well to be drilled in 2015 GR RES 1000 10400 10800 1050 1050 1000 10450 Average Cumulative Production of Similar/Offset Vertical Wells 77,000 bo + 2.2 bcf Average Cumulative Production of Similar/Offset Vertical Wells 26,000 bo + 1.1 bcf 118

Anadarko Basin Impact 2015 Activity 3 Rigs 18 23 wells Gross Upside Resource Potential (Medrano and Marchand Only) 300 400 wells 150 205 MMBoe ~60% Avg. WI 45% Liquids (27% Oil, 18% NGLs) Anadarko Basin Key Takeaway Points SOHOT delivering excellent production growth and economics with more potential growth possible from reservoirs to be tested in 2015 Many reservoirs are economically competitive with reservoirs in other basins Unit owns a large HBP acreage position and has over 40 years experience in the basin Basin contains multiple oil based and gas based reservoirs providing operators commodity price optionality in one geographical area 119

Granite Wash

Texas Panhandle Position Area Highlights: Net Acres: 40,600 96% HBP Buffalo Wallow 1,282 Wells 71% Operated 68% Working Interest Average Net Daily Prod 19 MBoe/d 49% Liquids Potential Locations 700 900 122

Granite Wash Historical Type Curve BOE / Day 10,000 1,000 100 10 60% 50% 40% 30% 20% 10% 0% 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 $70 / $3.50 / $80 / $3.50 / $24.50 $28 Management Strip see Appendix Rates of Return (%) Strip $90 / $4 / $31.50 Months $100 / $4 / $35 $100 / $4.50 / $35 Type Curve Average Production $110 / $4.50 / $38.50 Single Well Parameters: EUR: 596 MBOE Well Costs: $5.8 MM ROR: 32% Payout: 2.5 Years 200 300 Locations OIL EUR: 65 MBO IP (30 Day): 185 BBL/D GAS (SHRUNK) EUR: 1.7 BCF IP (30 Day): 2.2 MMCF/D NGL EUR: 250 MBO IP (30 Day): 320 BBL/D NGL Yield: 4.7 gal/mcf Gas Shrink: 24% 123

2015 Granite Wash Locations 124

Buffalo Wallow (500 600 Locations) Granite Wash A" Granite Wash A 1 10 20 20 30 11,057 TVD ( 8,264 SSTVD) 11,156 TVD ( 8,363 SSTVD) 11,363 TVD ( 8,570 SSTVD) 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 F 1 70 80 60 70 40 50 55 60 60 70 55 60 40 50 50 60 11,664 TVD ( 8,871 SSTVD) 11,868 TVD ( 9,075 SSTVD) 11,974 TVD ( 9,181 SSTVD) 12,245 TVD ( 9,452 SSTVD) 12,388 TVD ( 9,595 SSTVD) 12,504 TVD ( 9,711 SSTVD) 12,764 TVD ( 9,971 SSTVD) 13,000 TVD ( 10,207 SSTVD) Gross Thickness = 2,273 Feet Granite Wash G 40 50 13,330 TVD ( 10,537 SSTVD) 126

Buffalo Wallow (500 600 Locations) Zones Derisked GW B (60 70) 3 tests / 2 waiting on completion Zones Evaluating GW A2 (70 80) 1 waiting on completion GW C1 (55 60) 3 tests / 2 waiting on completion GW D (60 70) 1 test GW E (55 60) 4 tests GW F1 (50 60) 1 test GW G (40 50) 1 waiting on completion Zones Yet to Test GW A (10 20) GW A1 (20 30) GW C (40 50) GW F (40 50) 127

Buffalo Wallow GW B Type Curve BOE / Day 1,000 100 Type Curve Average Production Single Well Parameters: EUR: 887 MBOE Well Costs: $6.2 MM ROR: 20% Payout: 4 Years 10 30% 25% 20% 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 Months Rates of Return (%) Strip OIL EUR: 39 MBO IP (30 Day): 30 BBL/D GAS (SHRUNK) EUR: 3.4 BCF IP (30 Day): 2.7 MMCF/D 15% 10% 5% 0% $70 / $3.50 / $80 / $3.50 / $24.50 $28 Management Strip see Appendix $90 / $4 / $31.50 $100 / $4 / $35 $100 / $4.50 / $35 $110 / $4.50 / $38.50 NGL EUR: 285 MBO IP (30 Day): 220 BBL/D NGL Yield: 2.9 gal/mcf Gas Shrink: 17% 128

Buffalo Wallow GW C1 Plug and Perf 1,000 Meek #6834H Production Single Well Parameters: EUR: 612 MBOE Well Costs: $6.2 MM ROR: 34% Payout: 2.4 Years BOE / Day 100 OIL EUR: 80 MBO IP (30 Day): 120 BBL/D GAS (SHRUNK) EUR: 1.5 BCF IP (30 Day): 2.1 MMCF/D 10 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 Months NGL EUR: 280 MBO IP (30 Day): 400 BBL/D NGL Yield: 5.8 gal/mcf Gas Shrink: 26% 129

Buffalo Wallow GW E Plug and Perf 1,000 Single Well Parameters: Graham #4613H Production EUR: 562 MBOE Well Costs: $6.2 MM ROR: 16% Payout: 4.2 Years BOE/Day 100 OIL EUR: 24 MBO IP (30 Day): 31 BBL/D GAS (SHRUNK) EUR: 2.0 BCF IP (30 Day): 2.1 MMCF/D 10 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 Months NGL EUR: 212 MBO IP (30 Day): 230 BBL/D NGL Yield: 3.7 gal/mcf Gas Shrink: 19% 130

Buffalo Wallow Operational Efficiencies Completion Enhancements Increased fluid volume by 30% and proppant quantity by 80% Increased sand concentrations Addition of 100 mesh and 30/50 proppant More perforations clusters per stage SWD Infrastructure $1.5MM reduction in SWD costs per producing well 70% reduction in SWD expenses vs. hauling Produced Water Recycling Pits Synergy with SWD infrastructure Substantial freshwater conservation Over 1 million barrels recycled to date Large pits reduced development footprint Fracture treatment costs reduced OPEX Efficiencies Utilizing reverse gas lift Similar volumes as ESP with lower costs 68% reduction in OPEX 1 st 3 months Permanent power from start of operations 131

Granite Wash Drilling Cost Improvement $1,200 60 Drilling Cost Per Lateral Foot ($/ft) $1,000 $800 $600 $400 $200 50 40 30 20 10 Days $0 2010 2011 2012 2013 2014 YTD 2015 Estimate 0 Drilling Cost Per Lateral Foot Days 132

Granite Wash Net Cash Margin (Mcfe) Net Cash Margin $2.47 Revenue per Mcfe (3Q 2014 YTD) $6.10 Dry Gas 35% NGLs (C2+) 32% Condensate 33% Costs (Mcfe) F&D $2.03 Operating Costs $0.92 Prod. Taxes $0.21 G&A $0.47 Total Costs $3.63 Average Realized Prices September 2014 YTD: Oil $95.85, NGLs $32.59, Natural Gas $4.12 133

Granite Wash Impact 2015 Activity 2 4 Rigs 15 30 net wells Gross Upside Resource Potential 700 900 wells PUD: 80 PROB: 200 300 POSS: 420 520 420 540 MMBoe 70% Avg. WI 49% Liquids (9% oil, 40% NGLs) Granite Wash Key Takeaway Points Substantial number of drilling locations have in excess of 30% ROR in spite of lower commodity prices Large inventory of drilling locations on HBP acreage provides option to increase or decrease rig count to match commodity price environment Upsized fracture stimulations are being implemented in Buffalo Wallow to improve well economics 2015 drilling program is focused on highest ROR locations 134

Mississippian

Mississippian Impact 2015 Activity 1 Rig 5 20 wells Gross Upside Resource Potential 300 450 wells 45 70 MMBoe ~70% Avg. WI 71% Liquids (61% oil, 10% NGLs) 2,100 Mississippian Production 1,800 1,500 Boe/d 1,200 900 600 300 0 2012 2013 2014 est. 2015 est. NGLs Oil Gas 136

Mississippian Play Position Kansas Central Kansas Uplift Core Leasehold Horizontal Wells by Operator UNIT TAPSTONE CHESAPEAKE DEVON RANGE SANDRIDGE OTHER UNIT LEASEHOLD Net Acres: 153,000 32 Horizontal Wells 100% Operated 100% Working Interest Kansas Average Net Daily Prod 1,860 Boe/d 71% Liquids (61% Oil, 10% NGLs) Potential Locations 2 4 Wells / Section Oklahoma 137

Type Curve Geo Model/New Frack Not Applied 1000 Average Production 100 BOE / Day 10 1 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Months 138

Type Curve Geo Model/New Frack Applied 1000 Type Curve Average Production Single Well Parameters: BOE / Day 100 10 EUR: 150 MBOE Well Costs: $3.0 MM ROR: 55% Payout: 1.6 Years 1 160% 140% 120% 100% 80% 60% 40% 20% 0% 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Months Rates of Return (%) Strip $70/$3.50/$24.50 $80/$3.50/$28.00 $90/$4.00/$31.50 $100/$4.00/$35.00 $100/$4.50/$35.00 $110/$4.50/$38.50 Management Strip see Appendix OIL EUR: 110 MBO IP (30 Day): 290 BBL/D GAS (SHRUNK) EUR: 176 MMCF IP (30 Day): 315 MCF/D NGL EUR: 11 MBO IP (30 Day): 20 BBL/D NGL Yield: 2.1 gal/mcf 139

Mississippian Drilling $500 Drilling Cost Improvement 25 $450 Drilling Cost Per Lateral Foot ($/foot) $400 $350 $300 $250 $200 $150 $100 20 15 10 5 Days $50 $0 2012 2013 2014 YTD 2015 Estimate Drilling Cost Per Lateral Foot Days from Spud to Rig Release 0 140

Mississippian Net Cash Margin Revenue per Boe (3Q 2014 YTD) $68.36 ($/Boe) Net Cash Margin $17.71 Dry Gas 10% NGLs (C2+) 6% Oil 84% Costs ($/Boe) F&D $24.45 Operating Costs $15.42 Prod. Taxes $3.20 G&A $7.58 Total Costs $50.65 141

Highlights and Ongoing Optimizations 3D seismic acquisition to strengthen geologic model Common production facilities up to 4 wells/facility No water hauling. 3 SWD wells supporting 31 horizontal producers Identify optimal well spacing Lower drilling and completion costs further Extended lateral potential 142

Mississippian Impact 2015 Activity 1 Rig 5 20 wells Gross Upside Resource Potential 300 450 wells 45 70 MMBoe ~70% Avg. WI 71% Liquids (61% oil, 10% NGLs) Mississippian Key Takeaway Points Acreage position is largely contiguous and allows for controlled scalable operations Current well data with applied geologic model and new fracture stimulation has improved play economics significantly 3D seismic data acquisition should further improve geologic model Well costs are continuing to decrease while well EUR is increasing Synergy with both Unit Drilling and Superior 143

Financial Review

David Merrill Chief Financial Officer and Treasurer 145

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 (1) As of September 30, 2014 Borrowing Base $900 million Elected Commitment $500 million Outstanding $31 million Maturity September 2016 146

Liquidity for Financial Flexibility Solid borrowing base Rig fleet upside liquidity $1,000 (in millions) Debt Maturities $400 $500 $469 $650 $0 $31 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 Outstanding Borrowings Undrawn Credit Facility Undrawn Borrowing Base Senior Subordinated Notes 147

Historical Credit Ratios Total Debt / EBITDA EBITDA / Total Interest 1.2 1 100 80 0.8 0.6 0.4 0.2 0 0.1 0.4 0.5 1.1 1.0 1.0 2009 2010 2011 2012 2013 Sept. '14* 60 40 20 0 66.5 97.5 38.4 21.1 13.5 15.0 2009 2010 2011 2012 2013 Sept. '14* *12 months ended Sept. 14 $6.00 Debt / Proved Reserves ($/Boe) 30% Debt / Total Capitalization $4.00 20% $2.00 $0.00 $4.78 $4.04 $2.59 $1.57 $0.31 2009 2010 2011 2012 2013 10% 0% 27% 23% 22% 9% 13% 2% 2009 2010 2011 2012 2013 Sept. '14 148

Strong Debt Adjusted Reserve Growth Per Share 3 Year Average Debt Adjusted Reserve Growth (2011 2013) 140% 120% 100% 80% 19% 60% 40% 20% 14% Average 0% PVA SD KOG OAS REXX ROSE CLR SM COG SWN RRC UNT EQT CRK QEP AXAS DNR PETD PQ AREX WLL XEC NBL EOG APC LINE CHK BBG XCO UPL DVN APA NFX PXD ECA CRZO FST 20% 40% 60% Source: Bloomberg 149

Strong Production Growth KOG COG OAS EQT CLR REXX ROSE SM RRC LINE AREX UNT SWN WLL NBL PQ XEC EOG PXD AXAS APC CRZO PVA CHK DVN SD ECA DNR APA QEP 2013 Production Growth NFX UPL PETD XCO CRK BBG FST 110% 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 10% 20% 30% 40% 18% 12% Average Source: Bloomberg 150

6.0 X 5.0 X 4.0 X 3.0 X 2.0 X 0.9x 1.0 X 0.0 X KOG SD REXX XCO UPL LINE FST AXAS EOG SWN UNT XEC PXD COG APA WLL SM APC NBL CLR DVN ECA AREX EQT CRZO QEP PETD NFX CRK CHK RRC OAS PVA ROSE DNR BBG PQ Strong Financial Position Debt/2014 Estimated EBITDA 2.2x Average Source: Bloomberg 151

Conservative Reserve Position 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% CRZO CLR ROSE PETD PXD XEC UNT DVN CRK APC APA LINE CHK PQ FST ECA XCO SD DNR SWN NBL COG WLL NFX OAS EOG QEP UPL RRC SM EQT KOG AXAS REXX BBG PVA AREX 2013 Proved Developed Reserves 77% Source: Bloomberg 57% Average 152

Finding Costs All In Finding Costs ($/Boe) $30 $20 $10 $26.68 $23.73 $20.80 $17.00 $0 2010 2011 2012 2013 153

Segment Contribution EBITDA 40% 2008 4% 56% 2014 Forecast 25% 6% 69% Oil and Natural Gas Contract Drilling Midstream See appendix for adjusted EBITDA reconciliation. 154

Operating Segment Capital Expenditures Operating Segment Capital Expenditures (excluding acquisitions) 2008 28% 7% 65% 2014 Forecast 17% 6% 77% Oil and Natural Gas Contract Drilling Midstream 155

Planned and Opportunistic Monetization Non core asset sales 2011 $10 million 2012 $282 million 2013 $121 million 2014 YTD September $49 million 2015 (Potential)?? 156

Hedges 100,000 Natural Gas (MMBtu/d) 10,000 Crude Oil (Bbls/d) 80,000 $4.20 8,000 60,000 6,000 $91.06 40,000 $3.98 4,000 20,000 2,000 0 2014 2015 0 $95.00 2014 2015 157