Dahlman Rose Oil Service and Drilling Conference Wednesday, November 30, 2011 10:50 a.m.
Overview of Operations Tulsa based company founded in 1963 with long history of operations in the Mid-Continent Bakken 3% Ticker: UNT / NYSE Casper Office Market Cap: $2.4 billion (1) Enterprise Value: $2.7 billion (1) Proved Reserves: 104 MMBoe Oklahoma City Office Andarko Basin 55% Arkoma Basin Tulsa Headquarters 19% Percent Natural Gas: 68% Percent Proved Developed: 80% Drilling Rigs: 126 (2) Miles of Midstream Pipeline: 910 Permian Basin 4% Houston Office Gulf Coast Basin 16% North LA/ East Texas Basin 3% 121 7 E&P plays Unit Rigs New Rigs 2011 Superior Pipeline's Core Operations (1) Market data as of 11/18/2011. (2) Excludes two new builds operational in fourth quarter 2011. Integrated Business Approach NY005VRM_1.WOR
Summary of Business Strengths Integrated Approach Enhances Stability and Flexibility Integrated approach to business allows Unit to balance its capital deployment through the various stages of the energy cycle Vertical integration offers key advantages and provides industry intelligence on industry dynamics / trends Quality upstream asset base with significant growth potential Large development drilling inventory with attractive economics in current price environment, with significant horizontal drilling upside potential 191% average production replacement since 2001 Leading drilling services provider with highly capable fleet Average 1,200 HP for 126 rig fleet (1) 70% of fleet capable of drilling horizontal wells 120% increase in rig count since 2001 Midstream business generating incremental margin opportunities Focus in emerging plays of Granite Wash and Marcellus shale 513% increase in per day natural gas processed volumes since 2004 1,099% increase in per day liquids sold volumes since 2004 (1) Excludes 2 of the 7 new build rigs for 2011.
Core Upstream Producing Areas Permian Basin 4% Anadarko Basin 55% Tulsa Headquarters 19% Arkoma Basin North LA/East 3% Texas Basin Gulf Coast 16% Basin Houston Office 2010 reserves of 104 MMBoe were 68% natural gas and 80% proved developed Reserve life of approximately 9 years Beginning in late 2008, implemented strategy of increasing focus on liquids-rich and oil prospects Forecast to end 2011 with 38% liquids production Key focus areas include: Granite Wash (Texas Panhandle) Marmaton (Oklahoma Panhandle oil play) Wilcox (Gulf Coast) 2010 Proved Reserves (MMBoe) Q3 2011 Daily Production (MBoe/d) NGL 15% Oil 17% Gas 68% Oil 20% NGL 18% Gas 62% Proved Reserves: 104 MMBoe (1) Note: Map does not include 3% of proved reserves located in the Bakken shale play. Daily Production: 34.0 MBoe/d
Track Record of Reserve Growth Proved Reserves (MMBoe) 120 104 100 2001 2010 CAGR: 10% 95 96 86 79 80 69 58 60 42 45 48 40 20 0 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Oil / NGLs Natural Gas Annual Reserve Replacement (1) 300% 285% 261% 250% Minimum Target: 150% 221% 200% 186% 169% 166% 171% 176% 162% 164% (2) 150% 100% 113% 50% Stable and consistent economic growth of oil and natural gas reserves of at least 150% of each year s production 218% average annual reserve replacement over last 27 years Reserve growth driven by Oklahoma and Texas activity and a shift from vertical to horizontal / liquids-rich drilling (1) The Company uses the reserve replacement ratio as an indicator of the Company's ability to replenish annual production volumes and grow its proved reserves, including by acquisition, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not imbed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. 0% 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 (2) 164% based on previous SEC reporting standards.
Maintaining Production while Improving Commodity Mix Annual Production (MBoe/d) Production (MBoe/d) 35 28 25 24 29 28 2005-2011E CAGR: 10% 27 33 32 35 28 25 29 28 26 25 27 29 30 33 34 33 21 14 19 2005-2008 CAGR: 16% 21 14 7 7 0 Net Wells Drilled: 2005 2006 2007 2008 2009 2010 2011E 73 85 97 134 42 88 0 2007 2008 2009 Q1 Q2 Q3 Q4 Q1 Net Wells 2010 2010 2010 2010 2011 Drilled: 97 134 42 12 23 22 31 17 Q2 2011 20 Q3 2011 24 2011E Oil / NGLs Natural Gas Low End Projected Production High End Projected Production
Increasing Liquids Focus In the current commodity price environment, Unit continues to allocate capital towards higher rate of return liquids-rich production Liquids-rich focus strategy initiated in late 2008 With attractive economics and evolving technology, Unit continues to shift to more horizontal drilling Drilled three operated horizontal wells in 2009 Drilled 50 operated horizontal wells in 2010 Plan to drill 70 operated horizontal wells in 2011 Annual Production Mix (MBoe/d) Liquids 25% 2008 2009 2010 2011E Horizontal 18% Gas 75% Vertical 82% Liquids 27% Gross Wells Drilled Horizontal 29% Gas 73% Vertical 71% Liquids 31% 2008 2009 2010 2011E Horizontal 63% Gas 69% Vertical 37% Liquids 37% Horizontal 72% Gas 63% Vertical 28% Unit Continues to Execute on Its Strategy to Increase Its Liquids Portfolio and Drilling Economics
Granite Wash Play Q4 2010 Q3 2011 Results First sales on 21 operated Granite Wash horizontal wells Average 30-day IP = 6.7 MMcfe/day Average reserves: 4.1 Bcfe (47% oil & liquids) Current CWC: $5.4 MM (4,000 lateral, 11 stage frac) Type Log 7,200 Lower Douglas 9,700 10,500 Granite Wash 11,100 Upper Morrow Texas Oklahoma Unit 2011 Horizontal Wells Unit 2011 Non-op Horizontal Wells Unit Acreage Average working interest: 73% 2011 Projected 3-4 rigs drilling = 20 operated horizontal wells Cap Ex: $85 MM 36,000 net acres
Marmaton Oil Play +/- 6,200 Horizontal Lateral Target +/- 6,00 Marmaton Type Log Upper 400 Middle Lower Unit Focus Area Unit Acreage Completed and Producing Wells 2011 Wells (first half) Q4 2010 Q3 2011 Results First sales on 35 operated Marmaton horizontal wells Average 30-day IP = 239 Boe/day Average reserves: 130 MBoe (90% oil & liquids) Current CWC: $2.7 MM (4,000 lateral, 16 stage frac) Average working interest: 89% 2011 Projected 2 rigs drilling = 30-36 operated horizontal wells Cap Ex: $70 MM 84,000 net acres located primarily in Beaver County, OK
Wilcox Liquids Play 2003 to Q3 2011 West Wilcox Expansion (2008) Completed 105 wells at 74% success rate Q1 Q3 2011 Results Completed 13 wells at 69% success rate Average 30-day IP rate = 326 Boe/day 2008 Expansion 7,800 Upper 9,400 10,500 Middle 11,400 Wilcox South Expansion (2009) Approx. 151 sq. mi. Average reserves: 252 MBoe (50% oil & liquids) Average CWC: $3.5 MM Average working interest: 95% 2011 Projected 1 2 rigs drilling = 15-20 operated vertical wells Cap Ex: $50 MM Lower 12,000 12,900 Completed and Producing Wells 2011 Rig Schedule 48,000 net acres
Bakken Shale Q1- Q3 2011 Results First sales 10 wells Average 30-day IP rate = 1,140 Boe/day Average reserves: 736 MBoe 86% oil 2011 Projected 2 third party rigs drilling = 15-20 non-op horizontal wells Average CWC: $11.0 MM (9,000 lateral, 28 stage frac) Average working interest: 13% Cap Ex: $30 MM 13,400 net acres Currently Drilling Future Drilling
Acquired Properties Purchase Price: $30.5 Million Reserves: 31.2 Bcfe (99% natural gas) 83% proved developed Production: 7.8 MMcfe/day 55,000 Net Acres, 96% HBP Upside in Woodford Shale and Hartshorne Coal Unit Acreage Acquired Properties
2011 Upstream Capital Program $357 million drilling capital budget allocated principally to the liquids-rich Granite Wash, Marmaton, and Wilcox plays 8% increase in the drilling budget for 2011 Approximately $202 million allocated to Granite Wash, Oklahoma Marmaton oil play, and Texas Wilcox field operations (~57% of overall drilling budget) Current plan will provide Unit with 19% - 22% annual growth in production Total CapEx by Category Drilling CapEx by Region Other 18% Drilling 82% Wilcox 15% Granite Wash 27% Marmaton Oil 15% Bakken 8% Dry Gas 6% Other 29% 2011E CapEx Budget: $435 Million 2011E Capital Budget: $357 Million Focused Capital Program Emphasizes Higher Return Liquids-Rich Drilling Plays
Significant Drilling Presence in Attractive Producing Regions 126 rig fleet (excluding 2 of 7 new builds)(1) 10 5 Fleet average ~1,200 HP rating; ~16,484 ft depth capacity 70% of rigs capable of drilling horizontal 2 15 63% utilization rate for Q3 2011 Casper Office 100% of 39 1,200-1,700 HP rigs contracted at the end of the third quarter Tulsa Headquarters 69 7 Oklahoma City Office 121 Unit Rigs 7 (1) New Rigs - 2011 Two new builds operational in fourth quarter. Recently spent $55 million to refurbish / upgrade 30 rigs Identified ~20 additional sub 1,000 HP rigs with upgrade potential 2011 7 new build rig program (1,500 HP rigs) 20 Houston Office 2-3 year contracts for all 7 rigs, which will be deployed in the Bakken shale and Pinedale
Average Number of Rigs Utilized 100 75 50 25 0 2007 2008 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011
Diverse and Versatile Rig Fleet 0 400-700 h.p. 750-1,000 h.p. 1,200-1,700 h.p. 2,000 h.p. >2,500 h.p. 20% 40% Utilization Percentage (65% as of 11/18/11) 60% Growing demand from increased shallow horizontal drilling activity 39 of 39 working 80% 100% Number of Rigs: New Rigs - 2011: 77 rigs equipped with integrated top drives 30 39 39 7 72% 6 7 Average Depth Capacity: 16,484 feet
Conditions Support Improving Dayrates and Margins (1) $20,000 Margins / DayRates ($) $15,000 $10,000 $5,000 $0 2007 2008 2009 Q1 2010 Q2 2010 Q3 2010 Q4 2010 Q1 2011 Q2 2011 Q3 2011 Margins Day Rates Six Consecutive Quarters of Improving Day Rates and Margins (1) Margins are before elimination of intercompany rig profit.
Overview of Drilling Fleet Contracted Rig Commodity Mix Geographical Location Oil 17% Liquids Rich 63% Dry Gas 20% Anadarko Basin 30% TX Panhandle 26% Arkoma 6% E. TX, LA, GC, S. TX 12% Barnett 4% Rockies/Bakken 22% Rig Type HP Rating Mechanical 49% Electric 51% 1,200-1,700 34% 750-1,000 32% 450-700 24% 2,000 5% >2,500 5% Note: Based on 82 contracted rigs. All charts represent total 128 rig fleet.
Superior Pipeline s Core Operations Average Processing Pipeline Volume Average Capacity Processing (miles) Pipeline (MMbtu/d) Volume (MMcf/d) Capacity (miles) (MMbtu/d) (MMcf/d) Hemphill/Mendota 130 43,700 100 Perkins Hemphill/Mendota 55 130 5,600 43,700 10 100 Cashion Perkins 140 55 22,500 5,600 25 10 Minco Cashion 130 140 7,700 22,500 12 25 Minco 130 7,700 12 Panola (1) Panola (1) 45 52,000 - Segno 30 45 19,900 52,000 - - Segno 30 19,900 - (1) Includes two treatment plants. Three natural gas treatment plants Ten natural gas processing plants 34 active gathering systems 910 miles of pipeline
Historical Performance Historical Daily Gathering Volumes (MMBtu / d) 250,000 NGLs / Condensate Volumes (Bbl / d) 10,000 200,000 8,000 150,000 6,000 100,000 4,000 50,000 2,000 0 2006 2007 2008 2009 2010 9 mos. 2011 2010 Contract Mix (Based on Volume) (1) 0 2006 2007 2008 2009 2010 9 mos. 2011 2010 Contract Mix (Based on Operating Margin) (1) POP 33% Fee-Based 51% POI 47% POP 38% POI 16% Fee-Based 15% (1) POP represents percent of proceeds. POI represents percent of index.
Balance Sheet Summary Working Capital $57.9 $41.1 Total Assets 3,165.3 2,669.2 Long-Term Debt 9/30/11 12/31/10 (In Millions) Senior Subordinated Notes 250.0 --- Bank Facility 55.4 163.0 Total Long-Term Debt 305.4 163.0 Shareholders Equity 1,910.4 1,710.6 Credit Line Undrawn 194.6 162.0 Long-Term Debt to Total Capitalization 14% 9%
Senior Subordinated Notes First-time issuer (May 2011) $250 million aggregate principal amount 10-year maturity (2021) 6 5/8% coupon
Segment Contribution Revenues ($ millions) EBITDA ($ millions) (1) $1,400 $1,358 $800 $754 $1,200 $1,000 $800 $600 $710 $882 $863 $600 $400 $371 $442 $436 $400 $200 $200 $0 2008 2009 2010 9 mos. 2011 $0 2008 2009 2010 9 mos. 2011 Unit Petroleum Unit Drilling Superior Pipeline Other (1) See EBITDA reconciliation.
Adjusted Earnings per Share (1) $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2006 2007 2008 2009 2010 2011 First 9 mos. Year-End (1) See Adjusted EPS reconciliation to EPS.
Hedges Target 50 70% of current year projected oil and natural gas production Crude oil 63% in 2011 Natural gas 60% in 2011 Primarily utilize swaps and collars Current hedge portfolio consists of swaps Natural Gas Liquids Hedged 2,535 Bbls/day for balance of 2011 (40% of Q3 11 volumes) Hedged 2,210 Bbls/day for 1 st quarter of 2012 MMBtu/d Natural Gas Bbls/d Crude Oil 100,000 80,000 $4.70 6,000 $96.54 60,000 4,000 $84.28 $5.24 40,000 2,000 $102.05 20,000 0 2011 2012 0 2011 2012 2013
Capital Expenditures (In Thousands) $800,000 $600,000 $400,000 $200,000 $0 2006 2007 2008 2009 2010 2011 Budget Unit Petroleum Unit Drilling Superior Pipeline
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 forwardlooking. 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 forwardlooking statements. These include the factors discussed or referenced in the Risk Factors section of the Company s Prospectus Supplement filed with the Securities and Exchange Commission ( SEC ) pursuant to Rule 424 (b), 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.
Non-GAAP Financial Measures EBITDA Nine months ended September 30, Years ended December 31, ($ in Millions) 2010 2011 2008 2009 2010 Net Income $103 $144 $144 ($56) $146 Income Taxes 64 90 82 (32) 91 Depreciation, Depletion and Amortization 143 202 245 177 205 Impairment of Oil and Natural Gas Properties - - 282 281 - Interest Expense - 2 1 1 - EBITDA $310 $438 $754 $371 $442 Unit Petroleum Income Before Income Taxes (1) $129 $151 ($4) ($126) $177 Depreciation, Depletion and Amortization 82 132 160 115 119 Impairment of Oil and Natural Gas Properties - - 282 281 - EBITDA $211 $283 $438 $270 $296 Unit Drilling Income Before Income Taxes (1) $36 $95 $240 $51 $60 Depreciation and Amortization 49 57 70 45 70 EBITDA $85 $152 $310 $96 $130 Superior Pipeline Income Before Income Taxes (1) $11 $14 $16 $5 $17 Depreciation and Amortization 12 12 15 16 15 EBITDA $23 $26 $31 $21 $32 (1) Does not include allocation of G&A expense.
EPS Reconciliation 9 mos. 9 mos. 2008 2008 2009 2009 2009 2009 (in millions except per share amounts) Amount Per Share Amount Per Share Amount Per Share Net income before impairment of oil and natural gas properties $ 319.1 $ 6.80 $ 119.6 $ 2.52 $ 91.1 $ 1.92 Impairment of oil and natural gas properties (175.5) (3.74) (175.1) (3.70) (175.1) (3.71) Net Income (Loss) $ 143.6 $ 3.06 $ (55.5) $ (1.18) $ (84.0) $ (1.79)