Capital One Securities, Inc. Energy Conference December 11, 2013
Forward-Looking Statement This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. The words believe, expect, anticipate, plan, intend, foresee, should, would, could, or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including as to the Company s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management s expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced in the Risk Factors section of the Company s Offering Memorandum provided in connection with this offering, risks relating to financial performance and results, current economic conditions and resulting capital restraints, prices and demand for oil and natural gas, availability of drilling equipment and personnel, availability of sufficient capital to execute the Company s business plan, the Company s ability to replace reserves and efficiently develop and exploit its current reserves and other important factors that could cause actual results to differ materially from those projected. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The SEC generally permits oil and gas companies, in filings made with the SEC, to disclose only proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In this communication, the Company uses the term unproved reserves which the SEC guidelines prohibit from being included in filings with the SEC. Unproved reserves refers to the Company s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. Unproved reserves may not constitute reserves within the meaning of the Society of Petroleum Engineer s Petroleum Resource Management System or proposed SEC rules and does not include any proved reserves. Actual quantities that may be ultimately recovered from the Company s interests will differ substantially. Factors affecting ultimate recovery include the scope of the Company s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves may change significantly as development of the Company s core assets provide additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. This presentation contains financial measures that have not been prepared in accordance with U.S. Generally Accepted Accounting Principles ( non-gaap financial measures ) including LTM EBITDA and certain debt ratios. The non-gaap financial measures should not be considered a substitute for financial measures prepared in accordance with U.S. Generally Accepted Accounting Principles ( GAAP ). We urge you to review the reconciliations of the non-gaap financial measures to GAAP financial measures in the appendix. 2
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 Casper 17 Marcellus Anadarko Basin 74 Tulsa Headquarters Arkoma Basin 122 Unit Rigs E&P Plays Permian Basin Oklahoma City 15 North La/ East Texas Basin Mid-Stream Operations Houston 3 Office Location Gulf Coast Basin 3
Key Growth Points Exploration & Production 212% average production replacement since 2003 130% increase in liquids production since Q1 2009, when Unit began focusing almost entirely on increasing liquids production Proved reserves: 150 MMBoe (1) Drilling Grown rig count 39% since 2003 Sold 20 rigs since 2009, 5 under contract 122 drilling rig fleet Mid-Stream 144% increase in natural gas processing volumes since 2008 177% increase in daily liquids sold volumes since 2008 1,435 miles of pipeline Strong Balance Sheet Remains conservatively financed as the company has grown 4 (1) As of 12/31/2012.
Capital Allocation Criteria Oil and Natural Gas Segment Minimum 15% risk-adjusted ROR for new well proposals Contract Drilling Segment New build rigs minimum contract term of 2 to 3 years at a day rate sufficient to provide a 100% cash on cash payout during a 3 year term Rig Refurbishments minimum contract term sufficient to provide a 100% cash on cash payout during the initial term Midstream Segment Minimum 25% risk-adjusted ROR for POP/POI projects Minimum 15% risk-adjusted ROR for Fee Based projects 5
Core Upstream Producing Areas Marmaton Marmaton Mississippian Granite Wash Wilcox Beginning in late 2008, implemented strategy of increasing focus on liquids-rich and oil prospects Forecast 43% liquids production for 2013 Key focus areas include: Granite Wash (Texas Panhandle) Marmaton (Oklahoma Panhandle oil play) Wilcox (Gulf Coast) Mississippian (Kansas) 2012 reserves of 150 MMBoe were 62% natural gas and 79% proved developed Reserve life of approximately 10 years 2012 Proved Reserves Q3 2013 Daily Production NGL 23% NGL 24% Oil 15% Gas 62% Oil 19% Gas 57% 6 Proved Reserves: 150 MMBoe Daily Production: 45.8 MBoe/d
Track Record of Reserve Growth Proved Reserves (MMBoe) 160 140 120 100 80 60 40 20 0 2003 2012 CAGR: 15% 116 95 96 104 79 86 69 58 48 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Oil / NGLs Natural Gas 150 Stable and consistent economic growth of oil and natural gas reserves of at least 150% of each year s production 222% average annual reserve replacement over last 29 years Reserve growth driven by Oklahoma and Texas activity and a shift from vertical to horizontal / liquids-rich drilling Annual Reserve Replacement (1) 400% Minimum Target: 150% 337% 300% 200% 100% 0% 285% 261% 221% 202% 186% 166% 171% 176% 164% (2) 113% 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 (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. 7
Increasing Production while Improving Commodity Mix Annual Production (MBoe/d) 50 40 39 46 45 33 30 29 28 27 20 10 28% 55% 0 2008 2009 2010 2011 2012 2013E Net Wells Drilled: 134 43 88 82 80 8 Oil / NGLs Natural Gas Production Range
Granite Wash Play Noble acquisition strategic fit with existing UPC leasehold Total 48,000 net acres in the Texas Panhandle Core Area (81% HBP) Approximately 800 potential drilling locations HIGHLIGHTS Completed 72 operated horizontal wells since 2008 Production up 46% for nine mos. of 2013 over nine mos. of 2012 Calculated ROR 41% at strip* Granite Wash A" Granite Wash A-1 12 33 GW Type Log - Buffalo Wallow Field Current AFE CWC: $5.3 MM 2013 ACTIVITY Granite Wash A-2 Granite Wash B Granite Wash C 72 71 51 Q3 13 = average net 89 MMcfe per day (46% oil & NGLs) Granite Wash C-1 Granite Wash D Granite Wash E Granite Wash F Granite Wash F-1 68 70 61 49 54 Gross Thickness = 2,300 Feet First nine mos. 13: 14 wells completed 30 day IP = 5.0 MMcfe per day 4-6 Unit rigs: First sales on 27 gross wells Estimate capital expenditures $145 million net 9 Granite Wash G 54 * 11/1/13 strip pricing
Marmaton Oil Play Total 118,000 net acres in focus area (55% HBP) 150 potential locations on 640 acre spacing HIGHLIGHTS Completed 117 operated horizontal wells since 2010 Production up 38% in nine mos. 2013 over 2012 Calculated ROR 69% at strip* Current AFE CWC: $2.7 million per well Focus Area 2013 ACTIVITY Q3 13 average net 4,400 Boe per day (92% oil & NGLs) First nine mos. 13: 32 wells completed 30 day IP = 368 Boe per day Two Unit rigs estimate 42 gross completed wells Estimate capital expenditures $105 million net 10 * 11/1/13 strip pricing
Wilcox Liquids Play WILCOX HIGHLIGHTS Gilly Field Discovery Initial UPC discovery 2003 2003-2012 Completed 120 wells Gross cumulative production: 143 Bcfe (43% oil & NGLs) 2013 ACTIVITY Unit Prospect Area 53,100 net acres (29% HBP) Q3 2013 = average net 40 MMcfe per day Two Unit rigs in Wilcox; 10 12 gross wells Estimated AFE CWC: $5.4 million Gilly Field Discovery 220 Bcfe net resource potential Drilling first horizontal well ($9.5 million) Estimate capital expenditures $78 million net Gilly Field Discovery announced July 2012 2011-2012 wells Future wells Total resource potential = 302 Bcfe gross; 220 Bcfe net (30 Bcfe net proved YE 2012) Eight Wilcox potential pay zones (4 zones currently tested) Eight Gilly Field producing wells 11
Mississippian Play Total 133,000 net acres in focus area (6% HBP) at end of Q3 Approximately 300 potential locations (320 acre spacing) HIGHLIGHTS Central Kansas Uplift Seven horizontal Miss wells completed 30 day average IP 238 Boe per day Estimated reserve range = 125-180 MBoe Estimated AFE CWC: $3.0 million Mississippian Trend Focus Area Initial Well 105,000 Net Acres Mississippian Wells 2013 ACTIVITY Superior pipeline and plant construction completed in Q3 One Unit rig and potential second rig in Q4 First sales on 13 gross wells Estimate capital expenditures $40 million net 12
Significant Drilling Presence in Attractive Producing Regions 122 rig fleet 17 16 Casper Office Fleet average ~1,200 HP rating; 97% of contracted rigs drilling horizontal wells 51% utilization rate for Q3 2013 68% of 45 1,200-1,700 HP rigs under contract Refurbished 48 rigs since 2009 2012 placed 2 new build rigs into service (1,500 HP) 74 Oklahoma City Office Tulsa Headquarters Contracted Rig Commodity Mix Geographical Location 122 Unit Rigs 15 Houston Office Dry Gas 1% Liquids Rich 99% Rockies/ Bakken 27% E. TX, LA GC, S. TX 13% Anadarko Basin 60% 13 Note: Based on 67 contracted rigs. All charts represent total 122 rig fleet.
Average Dayrates and Margins (1) $20,000 90 Margins / DayRates ($) $15,000 $10,000 $5,000 60 30 Average Number of Rigs Utilized $0 2009 2010 2011 2012 9 mos. '13 0 Margins Day Rates Rigs Utilized 14 (1) Margins are before elimination of intercompany rig profit.
Rig Fleet Snap Shot 400 700 HP 750 1,000 HP 1,200 1,700HP 2,000 HP >2,000 HP 69% 31% 41% 59% 32% 68% 33% 67% 80% 20% Sale Pending: 4 29 41 44 3 5 % Utilized % Unutilized 70% of Total Fleet 15 86 rigs equipped with integrated top drives
Introducing the New BOSS Drilling Rig Optimized for Pad Drilling Multi-direction walking system Faster Between Locations Quick assembly substructure 32 truck loads More Hydraulic Horsepower (2) 2,200 horsepower mud pumps 1,500 gpm available with one pump Environmentally Conscious Dual-fuel capable engines Compact location footprint 16
Mid-Stream Core Operations Granite Wash 32,000 dedicated acres 1 processing facility 135 MMcf/d processing capacity 308 miles of gathering pipeline $12MM capital budget for 2013 Mississippi Lime 1,000,000+ dedicated acres 6 processing facilities 223 MMcf/d processing capacity* 500 miles of gathering pipeline $34.5MM capital budget for 2013 Pittsburgh Mills Hemphill Reno Bellmon Central & Eastern OK 200,000+ dedicated acres 540 miles of gathering pipeline 1 processing facility with 12 MMcf/d processing capacity 2 treating facilities with combined capacity of 190 GPM Marcellus Shale 43,000 dedicated acres 3 gathering systems 33 miles of gathering pipeline Segno East Texas 50 Miles of gathering pipeline Processing facilities Gathering systems Indicates Company Headquarters in Tulsa, Oklahoma Indicates Regional office in Pittsburgh, Pennsylvania *Includes 60 MMcf/d at Bellmon, which will be operational in Q4 17
Historical Performance Historical Daily Gathering Volumes (MMBtu / d) NGLs Volumes (Bbl / d) 400,000 15,000 300,000 10,000 200,000 100,000 5,000 0 2009 2010 2011 2012 9 mos. '12 9 mos. '13 0 2009 2010 2011 2012 9 mos. '12 9 mos. '13 Contract Mix (Based on Volume) 2012 Q3 2013 Contract Mix (Based on Operating Margin) 2012 Q3 2013 Fee Based 39% Fee Based 51% Fee Based 25% Fee Based 47% Commodity Based 59% Commodity Based 49% Commodity Based 75% Commodity Based 53% 18
Midstream Segment 2013 Outlook Mississippian Reno County, KS: 25 MMcf/d Total Processing Capacity 5 MMcf/d refrigeration plant completed and operational 20 MMcf/d cryogenic plant completed and operational Currently processing 2.8 MMcf/d Mississippian Bellmon: 90 MMcf/d Total Processing Capacity 30 MMcf/d cryogenic plant installed 60 MMcf/d cryogenic plant operational Q4 2013 Currently processing 30 MMcf/d 145 expected well connects in 2013 Connected 119 wells by the end of Q3 Consistent growth through greenfield construction of pipelines and processing plants in unconventional resource basins 19
Balance Sheet Summary 9/30/13 12/31/12 (In Millions) Total Assets 3,924.7 3,761.1 Long-Term Debt Senior Subordinated Notes 645.6 645.3 Bank Facility 71.1 Total Long-Term Debt 645.6 716.4 Shareholders Equity 2,116.9 1,974.3 Credit Line Undrawn 500.0 428.9 Long-Term Debt to Total Capitalization 23% 27% 20
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 September 2016 21 (1) As of September 30, 2013
Hedges Target 50 70% of current year projected oil and natural gas production Natural Gas Crude Oil MMBtu/d 100,000 $3.67 Bbls/d 10,000 80,000 8,000 $97.94 $93.26 60,000 $4.23 6,000 40,000 4,000 20,000 2,000 0 2013 2014 0 2013 2014 22
Segment Contribution Revenues ($ millions) Adjusted EBITDA ($ millions) (1) $1,400 $1,315 $800 $1,200 $1,208 $602 $657 $1,000 $800 $707 $871 $993 $600 $400 $373 $441 $474 $600 $400 $200 $200 $0 2009 2010 2011 2012 9 mos. '13 $0 2009 2010 2011 2012 9 mos. '13 Oil and Natural Gas Contract Drilling Midstream 23 (1) See appendix for adjusted EBITDA reconciliation.
Capital Expenditures (In Millions) $1,500 $1,000 $500 $0 2008 2009 2010 2011 2012 2013 Budget Oil and Natural Gas Contract Drilling Midstream Acquisitions 24
Non-GAAP Financial Measures Adjusted EBITDA Nine months ended Sept. 30, Years ended December 31, ($ in Millions) 2012 2013 2009 2010 2011 Net Income $80 $133 ($56) $146 Income Taxes 51 84 (32) 91 Depreciation, Depletion and Amortization 234 243 177 205 Impairment of Oil and Natural Gas Properties 116-281 - Interest Expense 5 12 1 - (Gain) loss on derivatives not designated as hedges and hedge ineffectiveness Settlements during the period of matured derivative contracts $196 123 281-4 2012 5 3 4 (1) (2) 1 - (1) (2) - - - Adjusted EBITDA $491 $474 $373 $441 $602 $657 $23 16 319 284 14 Unit Petroleum Income Before Income Taxes (1) $28 $174 ($121) $176 Depreciation, Depletion and Amortization 154 164 115 119 Impairment of Oil and Natural Gas Properties 116-281 - Adjusted EBITDA $298 $338 $275 $295 Unit Drilling Income Before Income Taxes (1) $135 $72 $51 $60 Depreciation and Amortization 63 53 45 70 Adjusted EBITDA $198 $125 $96 $130 Superior Pipeline Income Before Income Taxes (1) $7 $8 $5 $17 Depreciation and Amortization 16 24 16 15 Adjusted EBITDA $23 $32 $21 $32 $200 183 - $383 $135 80 $215 $17 16 $33 ($77) 211 284 $418 $159 81 $240 $6 24 $30 (1) Does not include allocation of G&A expense.